IEEE Power and Energy Society
STANDARDS
IEEE Standard for Interconnection and
Interoperability of Inverter-Based
Resources (IBRs) Interconnecting with
Associated Transmission Electric
Power Systems
Developed by the
Energy Development & Power Generation Committee, Electric Machinery
Committee, and Power System Relaying & Control Committee
IEEE Std 2800™-2022
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IEEE Std 2800™-2022
IEEE Standard for Interconnection and
Interoperability of Inverter-Based
Resources (IBRs) Interconnecting with
Associated Transmission Electric
Power Systems
Developed by the
Energy Development & Power Generation Committee, Electric Machinery
Committee, and Power System Relaying & Control Committee
of the
IEEE Power and Energy Society
Approved 9 February 2022
IEEE SA Standards Board
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Abstract: Uniform technical minimum requirements for the interconnection, capability, and lifetime
performance of inverter-based resources interconnecting with transmission and sub-transmission
systems are established in this standard. Included in this standard are performance requirements
for reliable integration of inverter-based resources into the bulk power system, including, but not
limited to, voltage and frequency ride-through, active power control, reactive power control,
dynamic active power support under abnormal frequency conditions, dynamic voltage support
under abnormal voltage conditions, power quality, negative sequence current injection, and system
protection. This standard also applies to isolated inverter-based resources that are interconnected
to an ac transmission system via dedicated voltage source converter high-voltage direct current
(VSC-HVDC) transmission facilities; in these cases, the standard applies to the combination of the
isolated IBRs and the VSC-HVDC facility, and not to an isolated inverter-based resource (IBR) on
its own.
Keywords: active power, capability, co-located resource, control, enter service, energy storage,
evaluation, fast frequency response, frequency, frequency response, harmonic current, harmonic
voltage, hybrid resource, IEEE 2800, integrity, interconnection, interoperability, inverter, inverterbased resource, isolation device, measurement accuracy, modeling, negative-sequence,
performance, positive-sequence, power quality, primary frequency response, protection, reactive
power, reference point of applicability, ride-through, solar photovoltaic power, standard, technical
minimum, transient overvoltage, type test, unbalance, verification, voltage, weak grid, wind power ·
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ISBN 978-1-5044-8463-3
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Participants
At the time this standard was completed, the Energy Development and Power Generation Committee had the
following officers:
Robert Thorton-Jones, Chair
Kai Strunz, Vice Chair
Michael Negnevitsky, Secretary
Zhenyu Fan, Standards Coordinator
John B. Yale, Past Chair
At the time this standard was completed, the Electric Machinery Committee had the following officers:
James Lau, Chair
Gayland Bloethe, Vice Chair
Edson Bortoni, Secretary
Kay Chen, Standards Coordinator
John Yagielski, Past Chair
At the time this standard was completed, the Power System Relaying Committee had the following officers:
Murty V. V. Yalla, Chair
Michael Thompson, Vice Chair
Gene Henneberg, Secretary
Don Lukach, Standards Coordinator
Russell Patterson, Past Chair
At the time this IEEE standard was completed, the Wind and Solar Plant Interconnection Performance
(WSPI-P) Working Group of the Energy Development and Power Generation Committee had the following
officers:
Jens C. Boemer, Chair
Bob Cummings, Babak Enayati, Ross Guttromson, Mahesh Morjaria, Chenhui Niu, Manish Patel,
Vice Chairs
Diwakar Tewari, Secretary & Treasurer
SubGroup Co-Leads & Facilitators
Jens C. Boemer, SubGroup I—Overall Document
Bob Cummings, SubGroup II—General Requirements
Rajat Majumder, SubGroup III—Active Power-Frequency Response
Rajat Majumder, Wesley Baker, SubGroup IV—Reactive Power-Voltage Control
Shun Hsien (Fred) Huang, SubGroup V—Low Short-Circuit Power
Ramesh Hariharan, SubGroup VI—Power Quality
Bob Cummings, SubGroup VII—Ride-Through Capability
Manish Patel, SubGroup VIII—Ride-Through Performance
Kamal Garg, Michael Jensen, SubGroup IX—Protection
Manish Patel, SubGroup X—Measurement and Modeling
Shazreen Meor Danial, Anderson Hoke, SubGroup XI—Tests and verification requirements
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In memoriam Kevin Collins, Vice-Chair.
Kevin Collins, our fellow P2800 Officer and Senior Technologist, PV Systems Development, at FirstSolar,
passed away unexpectedly in March 2020. On behalf of all Officers and Working Group members, our utmost
respect and heartfelt gratitude goes out to Kevin and his family. Kevin was at the heart of all the recent
activity in NERC IRPTF and IEEE P2800 since the beginning and will be missed. Kevin was a pioneer in
our industry and has been a cornerstone in our P2800 leadership team. His exceptional contributions in
creating the P2800 “strawman” as well as his thought leadership in facilitating SubGroup III (Active PowerFrequency Response) and SubGroup IV (Reactive Power-Voltage Control), will be remembered by the
industry. Kevin will also be missed as a calm, mature, and balanced voice of reason and empathy in P2800’s
high stakes-stakeholder consensus-building process.
The following working group members participated in finalizing the development of the standard with
working group inputs, and in facilitating the development of those inputs development process:
Hamid Abdelkamel
Syed Ahmad
Krishna Kumar Anaparthi
Noel Aubut
Christy Bahn
Behrooz Bahrani
Philip Baker
William Baker
Hassan Baklou
Abu Bapary
Adrien Bastos
John Bernecker
Debra Best
Rajesh Bhupathi
Sebastien Billaut
Lance Black
Jens C. Boemer
Kevin Brooks
Christopher Burge
Kristina Carmen
Chip Carter
Matthew Ceglia
Kay Chen
Gary Chmiel
Ritwik Chowdhury
Dinah Cisco
Frances Cleveland
Kevin Collins
Jose Cordova
Stephen Crutchfield
Bob Cummings
Randy Cunico
Kevin Damron
Shazreen Meor Danial
Ratan Das
David DeLoach
Alla Deronja
Dian Li Dianzi
James DiLuca
Sabrina Do
A. Doering
Daniel Du
Michael Edds
Antti Eerola
Mohamed Elkhatib
Babak Enayati
Jason Eruneo
Evangelos Farantatos
Roberto Favela
Martin Fecteau
Normann Fischer
Louis Fonte
Francisco Gafaro
James Gahan
John Gajda
Kamal Garg
Durga Gautam
Michael Gerber
Pramod Ghimire
Doug Gischlar
Jonathan Goldsworthy
Bo Gong
Ross Guttromson
Jean-Francois Hache
Aboutaleb Haddadi
Ramesh Hariharan
Jessica Harris
Patrick Hart
Philip Hart
Anderson Hoke
Ali Hooshyar
Pan Hu
Shun Hsien (Fred) Huang
Rich Hydzik
Faheem Ibrahim
Andrew Isaacs
Michael Jensen
Geza Joos
Prashant Kansal
Amir (Reza) Kazemi
Josh Kerr
Michael Kipness
Ruth Kloecker
Gary Kobet
Venkat Reddy Konala
Dan Kopin
Justin Kuhlers
Divya Kurthakoti
Sergey Kynev
Julie Lacroix
James Lau
Kathleen Lentijo
Andrew Leon
Jesse Leonard
Debra Lew
Chun Li
Shuhui Li
Zhen Li
Michael Lombardi
Olushola Jabari Lutalo
Min Lwin
Hongtao Ma
Bruce Magruder
Rajat Majumder
Sudip Manandhar
Gregory Marchini
Bradley Marszalkowski
Pierre-Luc Martel
Aristides Martinez
Jezzel Martinez
Barry Mather
Peter McGarley
Al McMeekin
Rick Meeker
Vahid Mehr
Jonathan Meyer
McPharlen Mgunda
Christopher Milan
Jeremiah Miller
Lipika Mittal
Amir Mohammednur
Mahesh Morjaria
Panayiotis Moutis
David Mueller
Anthony Murphy
Luigi Napoli
David Narang
Robert Nelson
Chenhui Niu
Robert O’Keefe
Mohamed Osman
Siddharth Pant
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Mahendra Patel
Manish Patel
Evan Paull
Blake D. Peck
Maryclaire Peterson
Jonathan Poirier
Pouyan Pourbeik
Allan Powers
Loren Powers
Ryan Quint
T. Raffield
Farrokh Rahimi
Janos Rajda
Deepak Ramasubramanian
Fernando Ramirez
Reynaldo Ramos
Amy Ridenour
Miguel Rios Rivera
Ciaran Roberts
Fabio Rodriguez
David Roop
Michael Ropp
Edward Ruck
Daniel Sabin
Allen Schriver
Harish Sharma
Nitish Sharma
Mark Siira
Mohit Singh
John Skeath
Gary Smullin
Sachin Soni
Michael Spector
Erin Spiewak
Craig Starr
Wayne Stec
Ravi Subramaniam
Eric Swanger
Diwakar Tewari
Geng Tian
Xingxin Tian
Lukas Unruh
Jim Van De Ligt
Rajiv Varma
Nath Venkit
Reigh Walling
Yi Wang
Robert White
Philip B. Winston
Stephen Wurmlinger
Sophie Xu
John B. Yale
Murty V. V. Yalla
Nicholas Zagrodnik
Malia Zaman
Hayk Zargaryan
David Zech
Jimmy Zhang
George Zhou
Kun Zhu
Songzhe Zhu
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The following members of the individual Standards Association balloting group voted on this standard.
Balloters may have voted for approval, disapproval, or abstention.
Hamid Abdelkamel
Robert Aiello
Roy Alexander
Marcelo Algrain
Eric Allen
Yazan Alsmadi
Erick Alves
Krishna Kumar Anaparthi
Jay Anderson
Galina Antonova
Andrew Arana
Daniel Arjona
Curtis Ashton
Noel Aubut
Jose Avendano-Mora
JiMyeong Bae
Philip Baker
William Baker
Peter Balma
Abu Bapary
Thomas Barnes
Paul Barnhart
Israel Barrientos
Jeffrey Barsch
Michael Basler
Thomas Basso
David Beach
Robert Beavers
Christopher Belcher
Sebastien Billaut
Wallace Binder
Richard Bingham
Sara Biyabani
Thomas Blackburn
William Bloethe
Jens C. Boemer
James Bougie
Theresa Bowie
Brian Boysen
Jeffrey Bragg
Terence Branch
Roland Brandis IV
Jon Brasher
Pablo Briff
Jeffrey Brogdon
Bill Brown
David Brown
Marlin Browning
Gustavo Brunello
Clayton Burns
Koti Reddy Butukuri
Thomas Callsen
Paul Cardinal
Michael Dana Carlson
Thomas Carpenter
Sean Carr
Juan Carreon
Richard Carter
Leo Casey
Divya Chandrashekhara
Pin Chang
Wen-Kung Chang
Suresh Channarasappa
Brittany Chapman
Thanga Raj Chelliah
Kay Chen
Ke Chen
Zhilei Chen
Gary Chmiel
Iker Chocarro
Ritwik Chowdhury
Dinah Cisco
Frances Cleveland
Nancy Connelly
Larry Conrad
Stephen Conrad
Michael Cowan
Timothy Croushore
Curtis Cryer
Bob Cummings
Randall Cunico
Patrick Dalton
Shazreen Meor Danial
Ratan Das
David Deloach
Alla Deronja
Eugene Dick
David Dickmander
Mamadou Diong
Thomas Domitrovich
Kevin Donahoe
Michael Dood
Neal Dowling
Herbert Dreyer
Donald Dunn
Benjamin Ealey
Michael Edds
Antti Eerola
Mohamed Elkhatib
Paul Elkin
Zakia El Omari
Zia Emin
Babak Enayati
William English
Johan H. Enslin
Lei Ertao
Evangelos Farantatos
Roberto Favela
Martin Fecteau
Kevin Fellhoelter
James Feltes
Curtis Fischer
Normann Fischer
Rostyslaw Fostiak
Dale Fox
Carl Fredericks
Regina Gao
Rafael Garcia
Kamal Garg
Shubhanker Garg
Jonathan Gay
Michael Geocaris
Kenneth Gettman
Farangmeher Ghadiali
Pramod Ghimire
Jalal Gohari
Bo Gong
Lou Grahor
Henry Gras
Stephen Grier
Glenn Griffin
J. Travis Griffith
Keith Grzegorczyk
Nathan Gulczynski
Mark Gutzmann
Aboutaleb Haddadi
Joshua Hambrick
Ramesh Hariharan
Robert Harris
Kyle Hawkings
Roger Hayes
Roger Hedding
Kyle Heiden
Gene Henneberg
Steven Hensley
Mariana Hentea
Chris Heron
Lee Herron
Michael Higginson
Ryan Hinkley
Werner Hoelzl
Robert Hoerauf
Anderson Hoke
Ali Hooshyar
Eric Hope
Sheikh Jakir Hossain
John Houdek
Yi Hu
Shun-Hsien (Fred) Huang
Richard Hunt
Faiz Ikramulla
Michael Ingram
Andrew Isaacs
Dmitry Ishchenko
Richard Jackson
Brad Jensen
Michael Jensen
Anthony Johnson
Brian Johnson
Jay Johnson
Steven Johnston
Andrew Jones
Innocent Kamwa
Prashant Kansal
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Gordon Kawaley
John Kay
Amir (Reza) Kazemi
Peter Kelly
Yashar Kenarangui
Chad Kennedy
Gael Kennedy
Sheldon Kennedy
Gregory Kern
Stuart Kerry
Irfan Khan
Yuri Khersonsky
James Kinney
Gary Kobet
Boris Kogan
Zaccaria Koita
Venkat Reddy Konala
Lawrence Kotewa
Benjamin Kroposki
Justin Kuhlers
Jacob Kulangara
Jim Kulchisky
Vinoth Kumar
Ruediger Kutzner
Hillmon Ladner-Garcia
Thomas Ladson
Chung-Yiu Lam
Daniel Lambert
Mario Lanaro
Justin Lane
Andrew Larkins
Raluca Lascu
James Lau
An Le
Daniel Lebeau
Wei-Jen Lee
Andrew Leon
Giancarlo Leone
Debra Lew
Shuhui Li
Ting Li
William Lockley
Michael Lombardi
Federico Lopez
Olushola Jabari Lutalo
Brian Lydic
Bruce Mackie
Afshin Majd
Rajat Majumder
Mario Manana Canteli
Tapan Manna
Timothy Marrinan
Hugo Marroquin
Bradley Marszalkowski
John Martin
Barry Mather
Slobodan Matic
Kevin Mayor
James McConnach
Ed McCullough
Thomas McDermott
Jeffrey McElray
Peter McGarley
Hank McGlynn
Sean McGuinness
Brian McMillan
Peter McNutt
Robert Messel
McPharlen Mgunda
Christopher Milan
Dean Miller
Nicholas Miller
James Mirabile
Bhaskar Mitra
Jeff Mizener
Ali Moeini
Sepehr Mogharei
Hossein Ali Mohammadpour
Amir Mohammednur
Jose Monteiro
Mahesh Morjaria
Christopher Mouw
Adi Mulawarman
Jerry Murphy
Anthony Murphy
Pratap Mysore
K. R. M. Nair
Anthony Napikoski
Arun Narang
David Narang
Alexandre Nassif
Cesar Negri
Dennis Neitzel
Steven Nelson
Robert Nelson
Arthur Neubauer
Kwok Kei Simon Ng
James Niemira
Joe Nims
Nayeem Ninad
Chenhui Niu
Samuel Norman
Matthew Norwalk
James O’Brien
Robert O’Keefe
Mohamed Osman
Umut Ozdogan
Sivaraman P.
Lorraine Padden
Marty Page
Siddharth Pant
Dwight Parkinson
Bansi Patel
Mahendra Patel
Manish Patel
Pathik Patel
Subhash Patel
Marc Patterson
Arumugam Paventhan
Stephen Pell
Howard Penrose
Branimir Petosic
Christopher Petrola
Sylvain Plante
Jeffrey Pond
Pouyan Pourbeik
Allan Powers
William Quaintance
Patrick Quinn
Ryan Quint
Ulf Radbrandt
Ion Radu
Bradley Railing
Deepak Ramasubramanian
Benito Ramos
Moises Ramos
Reynaldo Ramos
Lakshman Raut
James Reilly
Mark Reynolds
Miguel Rios Rivera
Bruce Rockwell
Diego Rodriguez
Charles Rogers
David Roop
Michael Ropp
James Rossman
Edward Ruck
Christopher Ruckman
Daniel Sabin
Christian Sanchez
Janette Sandberg
William Saylor
Steven Saylors
Bartien Sayogo
Allen Schriver
Carl Schuetz
Robert Schultz
Dustin Schutz
Kenneth Sedziol
Uwe Seeger
Daniel Seidel
Edward Seiter
Robert Seitz
Gab-Su Seo
Alkesh Shah
Devki Sharma
Harish Sharma
Nitish Sharma
Robert Sherman
Nigel Shore
Stephen Shull
Mark Siira
Hyeong Sim
Gaurav Singh
Mohit Singh
John Skeath
James Smith
Jerry Smith
Joshua Smith
Gary Smullin
Sachin Soni
Joseph Sowell
Michael Spector
Lincoln Sprague
Wayne Stec
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Andrew Steffen
Eugene Stoudenmire
Candace Suh-Lee
Chase Sun
Scott Sweat
Humayun Tariq
David Tepen
Diwakar Tewari
Michael Thompson
Robert Thornton-Jones
Xingxin Tian
Craig Turner
Eric Udren
Lukas Unruh
Onur Usmen
Jaryn Vaile
James Van De Ligt
Benton Vandiver
Luis Vargas
Rajiv Varma
Jason Varnell
Gerald Vaughn
Nath Venkit
John Vergis
Jane Verner
Quintin Verzosa
Ilia Voloh
Sandeep Vuddanti
Matthew Wakeham
Sukhdev Walia
Sarah Walinga
Christopher Walker
David Wallace
Reigh Walling
Peter Walsh
John Wang
Joe Warner
John Webb
Kenneth White
Robert White
Kevin Whitener
Aaron Wilson
Philip B. Winston
Rachel Wood
Terry Woodyard
Stephen Wurmlinger
John Yagielski
John B. Yale
Murty V. V. Yalla
Richard York
Oren Yuen
Kipp Yule
Mohammad Reza Dadash Zadeh
Nicholas Zagrodnik
Abu Zahid
Vahraz Zamani
Francisc Zavoda
David Zech
Timothy Zgonena
Jinhua Zhang
Cezary Zieba
Karl Zimmerman
When the IEEE SA Standards Board approved this standard on 9 February 2022, it had the following
membership:
David J. Law, Chair
Vacant Position, Vice Chair
Gary Hoffman, Past Chair
Konstantinos Karachalios, Secretary
Edward A. Addy
Ted Burse
Ramy Ahmed Fathy
J. Travis Griffith
Guido R. Hiertz
Yousef Kimiagar
Joseph L. Koepfinger*
Thomas Koshy
John D. Kulick
Johnny Daozhuang Lin
Kevin Lu
Daleep C. Mohla
Andrew Myles
Damir Novosel
Annette D. Reilly
Robby Robson
Jon Walter Rosdahl
Mark Siira
Dorothy V. Stanley
Lei Wang
F. Keith Waters
Karl Weber
Sha Wei
Philip B. Winston
Daidi Zhong
*Member Emeritus
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Introduction
This introduction is not part of IEEE Std 2800-2022, IEEE Standard for Interconnection and Interoperability of InverterBased Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems.
IEEE Std 2800™ was the first of a series of standards developed by IEEE Power and Energy Society Energy
Development and Power Generation Committee concerning transmission-connected inverter-based resources
interconnection. The additional documents in that series are as follows:

IEEE P2800.1 6 provides guidance on (conformance) test (and verification) procedures for inverterbased resources interconnecting with associated transmission systems (TSs).

IEEE P2800.2™ provides recommended practices on conformance tests and verification procedures
for inverter-based resources interconnecting with transmission and sub-transmission systems.
As with any IEEE standard, the applicability of IEEE Std 2800, IEEE P2800.1, or IEEE P2800.2 to given
IBR is determined by the authority governing interconnection requirements (AGIR) for that location. IEEE
P2800.1 and IEEE P2800.2 are under development at the time of this standard’s adoption, and their drafts
are designated IEEE P2800.1 and IEEE P2800.2, respectively.
The first publication of IEEE Std 2800 was an outgrowth of the recommendations from the North American
Electric Reliability Corporation (NERC) Inverter-Based Resources Performance Reliability Guideline
[B75] 7 and IEEE Std C57.12.80™ [B63]. Instances in this standard where the entities involved and
coordinating in the IBR interconnection process, i.e., TS owner, TS operator, load balancing entity, IBR
owner, IBR operator, and IBR developer, are mentioned and resemble functional responsibilities of the North
American regulatory framework; AGIRs are encouraged to adopt this standard with entity functional
responsibilities as applicable to the given regulatory framework.
Acknowledgements
Grateful acknowledgements to the Inverter-Based Resources Performance Working Group (IRPWG) of the
North American Electric Reliability Corporation (NERC) that provided their Reliability Guideline
Improvements to Interconnection Requirements for BPS-Connected Inverter-Based Resources [B76] as a
strawman for an early draft of this standard.
Permissions have been granted as follows:
Definitions in 3.1 reprinted or modified with permission from International Electrotechnical Commission (IEC):

Maximum current ac, Imax (IEEE Std C62.39™-2012, modified from IEC 62319-1:2005)

IBR continuous rating (ICR) (adapted from IEC 62934 ED1)

Mode (adapted from IEC 904-03-09)

Solar photovoltaic system (solar PV) (adapted from IEC 60050)

Wind turbine generator (WTG) (adapted from IEC 60050)
Figure 5 reprinted with permission from the Electric Power Research Institute (EPRI), © 2020.
Figure 10 reprinted with permission from The Regents of the University of California through Lawrence
Berkeley National Laboratory, © 2020.
The author thanks the International Electrotechnical Commission (IEC) for permission to reproduce
information from its International Standards. All such extracts are copyright of IEC Geneva, Switzerland.
6
Numbers preceded by P are IEEE authorized standards projects that were not approved by the IEEE-SA Standards Board at the time
this publication went to press. For information about obtaining drafts, contact the IEEE.
7
The numbers in brackets correspond to the numbers of the bibliography in Annex A.
13
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All rights reserved. Further information on the IEC is available from www.iec.ch. IEC has no responsibility
for the placement and context in which the extracts and contents are reproduced by the author, nor is IEC in
any way responsible for the other content or accuracy therein.
IEC 60050-904 ed.1.0 Copyright © 2014 IEC Geneva, Switzerland. www.iec.ch
IEC 60050-602 ed.1.0 Copyright © 1983 IEC Geneva, Switzerland. www.iec.ch
IEC 62319-1-1 ed.1.0 Copyright © 2005 IEC Geneva, Switzerland. www.iec.ch
IEC 62934:2021 Copyright © 2021 IEC Geneva, Switzerland.www.iec.ch
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Contents
1. Overview ...................................................................................................................................................18
1.1 General ...............................................................................................................................................18
1.2 Scope ..................................................................................................................................................19
1.3 Purpose ...............................................................................................................................................19
1.4 General remarks and limitations .........................................................................................................19
1.5 Word usage .........................................................................................................................................25
2. Normative references.................................................................................................................................25
3. Definitions, acronyms, and abbreviations .................................................................................................26
3.1 Definitions ..........................................................................................................................................26
3.2 Acronyms and abbreviations ..............................................................................................................39
4. General interconnection technical specifications and performance requirements .....................................41
4.1 Introduction ........................................................................................................................................41
4.2 Reference points of applicability (RPA) .............................................................................................43
4.3 Applicable voltages and frequency .....................................................................................................44
4.4 Measurement accuracy .......................................................................................................................45
4.5 Operational measurement and communication capability ..................................................................46
4.6 Control capability requirements..........................................................................................................46
4.7 Prioritization of IBR responses ...........................................................................................................47
4.8 Isolation device ...................................................................................................................................48
4.9 Inadvertent energization of the TS......................................................................................................48
4.10 Enter service .....................................................................................................................................48
4.11 Interconnection integrity ...................................................................................................................49
4.12 Integration with TS grounding ..........................................................................................................50
5. Reactive power-voltage control requirements within the continuous operation region .............................51
5.1 Reactive power capability...................................................................................................................51
5.2 Voltage and reactive power control modes .........................................................................................55
6. Active-power—frequency response requirements.....................................................................................57
6.1 Primary frequency response (PFR) .....................................................................................................57
6.2 Fast frequency response (FFR) ...........................................................................................................62
7. Response to TS abnormal conditions ........................................................................................................68
7.1 Introduction ........................................................................................................................................68
7.2 Voltage ...............................................................................................................................................68
7.3 Frequency ...........................................................................................................................................79
7.4 Return to service after IBR plant trip ..................................................................................................82
8. Power quality .............................................................................................................................................83
8.1 Limitation of voltage fluctuations induced by the IBR plant ..............................................................83
8.2 Limitation of harmonic distortion .......................................................................................................84
8.3 Limitation of overvoltage contribution ...............................................................................................87
9. Protection...................................................................................................................................................88
9.1 Frequency protection ..........................................................................................................................88
9.2 Rate of change of frequency (ROCOF) protection .............................................................................89
9.3 AC voltage protection .........................................................................................................................89
9.4 AC overcurrent protection ..................................................................................................................89
9.5 Unintentional islanding protection......................................................................................................89
9.6 Interconnection system protection ......................................................................................................90
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10. Modeling data ..........................................................................................................................................90
11. Measurement data for performance monitoring and validation ...............................................................92
12. Test and verification requirements ..........................................................................................................98
12.1 Introduction ......................................................................................................................................98
12.2 Definitions of verification methods ..................................................................................................98
12.3 Conformance verification framework .............................................................................................101
Annex A (informative) Bibliography ..........................................................................................................106
Annex B (informative) Inverter-based resource (IBR) interconnection examples ......................................112
B.1 AC interconnection examples ..........................................................................................................112
B.2 DC interconnection examples ..........................................................................................................114
B.3 Complex IBR plant examples ..........................................................................................................115
Annex C (informative) Inverter stability and system strength.....................................................................119
C.1 Introduction to transmission-connected inverter-based resources (IBRs) ........................................119
C.2 System strength and select metrics ..................................................................................................123
C.3 Inverter-based resource stability ......................................................................................................130
C.4 Grid-forming inverters .....................................................................................................................136
Annex D (informative) Illustration of voltage ride-through capability requirements ..................................140
D.1 Interpretation of voltage ride-through capability requirements .......................................................140
D.2 Informative figures for voltage ride-through capability requirements .............................................143
Annex E (informative) Recommended practices for voltage harmonics of inverter-based resources (IBRs)
.....................................................................................................................................................................146
E.1 Introduction ......................................................................................................................................146
E.2 Harmonic limits ................................................................................................................................149
E.3 Verification and adherence evaluation .............................................................................................149
Annex F (informative) Guidance on setting protection with inverter-based resources (IBRs)....................151
F.1 Frequency protection ........................................................................................................................151
F.2 Rate of change of frequency (ROCOF) protection ...........................................................................151
F.3 AC voltage protection.......................................................................................................................151
F.4 AC overcurrent protection ................................................................................................................152
F.5 Unintentional islanding protection ...................................................................................................152
F.6 Interconnection system protection ....................................................................................................153
Annex G (informative) Recommendation for modeling data ......................................................................154
G.1 General.............................................................................................................................................154
G.2 Steady-state modeling data requirements ........................................................................................154
G.3 Stability analysis dynamic modeling data requirements ..................................................................156
G.4 Electromagnetic transient (EMT) dynamic modeling data requirements ........................................157
G.5 Power quality, flicker, and rapid voltage change (RVC) modeling data requirements ....................160
G.6 Short-circuit modeling data requirements ........................................................................................160
Annex H (informative) Data that transmission system (TS) owner and TS operator may provide to the
inverter-based resource (IBR) developer .....................................................................................................161
H.1 System data ......................................................................................................................................161
H.2 Interconnection ratings ....................................................................................................................163
Annex I (informative) Illustration of voltage ride-through performance requirements ...............................164
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Annex J (informative) Type III wind turbine generator (WTG) challenges with controllability of negativesequence current during unbalanced faults ..................................................................................................168
Annex K (informative) Guidance on fast frequency response (FFR) ..........................................................170
K.1 Introduction to FFR variants ............................................................................................................170
K.2 Variants of FFR ...............................................................................................................................170
K.3 Conditions for return to normal operations ......................................................................................173
K.4 Performance when returning to normal operations ..........................................................................173
Annex L (informative) Damping ratio .........................................................................................................174
Annex M (informative) Consecutive voltage deviation ride-through capability of isolated inverter-based
resources (IBRs) interconnected via voltage source converter high-voltage direct current (VSC-HVDC).177
17
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IEEE Standard for Interconnection and
Interoperability of Inverter-Based
Resources (IBRs) Interconnecting with
Associated Transmission Electric
Power Systems
1. Overview
1.1 General
The global increase in penetration levels of inverter-based resources (IBRs) is expected to significantly
change the dynamic performance of the power grid. As the penetration levels of inverter-based resources
increase and the technology of inverter-based resources evolves, specifications and standards are needed to
address the performance requirements of inverter-based resources. Currently, there is no single document of
consensus on the performance requirements covering inverter-based resources interconnected with
transmission and sub-transmission systems. Events in North America, such as the Blue Cut Fire Disturbance
(NERC “1,200 MW Fault” [B72]) as well as the inappropriate use of IEEE Std 1547™ [B50] for large-scale
solar plants, underscore this need. 8 This new standard is a first attempt to address the need for consensusbased performance requirements and can help equipment manufacturers, project developers, transmission
planners, and power grid operators improve the quality of the inverter and facility performance to enhance
the stability of the power grid over a transmission planning horizon. 9 The specified requirements are intended
to strike a balance between the state of the art and forward-looking technology capabilities, while considering
the uncertainties as to how a future bulk power system with high amounts of IBR may be planned and
operated. Given that IEEE standards are voluntary industry standards, enforcement of any of the requirements
specified in this standard will require its adoption by the regional authority governing interconnection
requirements (AGIR). An AGIR is a cognizant and responsible entity that defines, codifies, communicates,
administers, and enforces the policies and procedures for allowing electrical interconnection of inverterbased resources interconnecting with associated transmission systems.
8
An Inverter-Based Resource Performance Task Force (IRPTF) of the North American Electric Reliability Corporation (NERC) issued
a white paper [B74] identifying gaps in NERC Reliability Standards, including FAC-001-3 [B90], FAC-002-2 [B91], MOD-026-1
[B93], MOD-027-1 [B94], PRC-002-2 [B96], PRC-024-2 [B97], TPL-001-4 [B98], VAR-002-4.1 [B99]; standard authorization requests
(SARs) are underway to close these gaps.
9
Transmission planning may address bulk system stability over the next one or two decades.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
1.2 Scope
This standard establishes the required interconnection capability and performance criteria for inverter-based
resources interconnected with transmission and sub-transmission systems. 10, 11, 12 Included in this standard
are performance requirements for reliable integration of inverter-based resources into the bulk power system,
including, but not limited to: voltage and frequency ride-through, active power control, reactive power
control, dynamic active power support under abnormal frequency conditions, dynamic voltage support under
abnormal voltage conditions, power quality, negative sequence current injection, and system protection. This
standard shall also be applied to isolated inverter-based resources that are interconnected to an ac
transmission system via a dedicated voltage source converter high-voltage direct current (VSC-HVDC)
transmission facility; in these cases, the standard shall apply to the combination of the isolated IBR and the
VSC-HVDC facility and shall not apply to the isolated IBR unless they serve as a supplemental IBR device
that is necessary for the IBR plant with VSC-HVDC to meet the requirements of this standard at the reference
point of applicability.
1.3 Purpose
This standard provides uniform technical minimum requirements for the interconnection, capability, and
performance of inverter-based resources interconnecting with transmission and sub-transmission systems.
1.4 General remarks and limitations
The criteria and requirements in this document are applicable to all inverter-based resource technologies
interconnected to transmission systems (TSs) (i.e., both meshed/networked and radial transmission and subtransmission) voltage levels. For radial sub-transmission systems, this standard intentionally overlaps with
potential application of IEEE Std 1547™, in which case it remains at the discretion of the authority governing
interconnection requirements (AGIR) to decide which standard is applicable.
The application of this standard may be limited to IBR plants for which interconnection requests are
submitted after the date by which this standard is enforced by the responsible authority governing
interconnection requirements (AGIRs); this standard may not apply to IBR plants that are either already
interconnected or for which interconnection requests had been submitted prior to the standard’s enforcement
date (grandfathering). Any substantial changes in an existing IBR plant, e.g., the “repowering” of a wind
power plant, may require retrofitting that IBR plant to meet all of the requirements of this standard.
The stated capability and performance requirements are universally needed for interconnection of IBR plants
to transmission and sub-transmission systems and their interoperability, and will be sufficient for most
installations. This standard specifies technical minimum interconnection, capability, and performance
requirements for an IBR plant, its IBR unit(s), and if present and as applicable, its supplemental IBR
device(s). 13 While this standard specifies uniform technical minimum requirements, the TS operator and TS
owner may, in a non-discriminatory way, specify different and/or additional requirements than those
specified in this standard for the safe and reliable operations of their system. Non-compliance of the IBR
10
Requirements apply to inverter-based resources (IBRs) only, e.g., solar photovoltaic, wind, and energy storage systems or
combinations of such. This excludes any systems that are not resources, e.g., flexible ac transmission systems (FACTS) and synchronous
condensers, and any resources that are not inverter-based, e.g., gas and steam power plants with synchronous generators.
11
This standard does not explicitly specify requirements for HVDC. However, it specifies requirements for inverter-based resources
(generation and storage) and that includes isolated IBR that are interconnected to an ac transmission system via a dedicated voltage
source converter (VSC) high-voltage direct current (HVDC) transmission facility, e.g., an offshore wind park. In these cases, the
combination of isolated IBR and VSC-HVDC transmission facility is regarded as the IBR to which this standard is applicable. This
standard is not intended to specify requirements for VSC-HVDC that connect two buses in a meshed synchronous ac system.
12
Resources with doubly-fed generators (DFGs) are defined as IBR, but requirements specified for IBR plants with DFG in this standard
may slightly differ, where appropriate.
13
Most of the requirements specified in this standard apply to the IBR plant; however, they are not intended to apply to each equipment
within the IBR plant. When designing components within an IBR plant it is normally necessary to consider the applicable design
standards, but it may also be necessary to meet more stringent requirements as determined in the IBR plant design evaluation (see
12.2.3).
19
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
owner with requirements specified by the TS operator or the TS owner that are different from, or in addition
to those requirements that are explicitly specified in this standard does not constitute non-compliance with
this standard.
A “capability requirement” in this standard specifies that the IBR plant (and where applicable, IBR unit[s])
shall be able to provide a function, configuration, or performance as determined by design, installation, and
operational status of equipment and control systems. A “performance requirement” in this standard specifies
the IBR plant’s (and where applicable, the IBR unit’s) behavior when executing a specified function or mode,
or when responding to a change in conditions.
NOTE 1—A “capability requirement” is, in colloquial terms, a requirement that ensures the IBR plant (or IBR unit) is
“ready to go at the flip of a switch.” This is more stringent than a “readiness requirement” that is in colloquial terms a
requirement that ensures the IBR plant (or IBR unit) is “almost ready to go,” for example, by having at least all interfaces
that are needed to (easily) retrofit the IBR with certain equipment and controls that can provide a specified capability.
The concept of readiness is not used in this standard. 14
NOTE 2—A “performance requirement” is not an “utilization requirement.” An “utilization requirement” is, in colloquial
terms, a requirement that ensures the IBR plant (or IBR unit) is “actually providing” a specified performance, for example,
by enabling a specified capability that makes the IBR continuously deliver a performance consistent with the specified
default values for functional settings. As clarified in the list of what remains outside the scope of this standard below,
requirements for utilization of any of the capabilities specified in this standard are outside the scope of this standard.
Authorities governing interconnection requirements should adopt this standard with functional
responsibilities for entities involved in and coordinating in the IBR interconnection process, i.e., TS owner,
TS operator, load balancing entity, IBR owner, IBR operator, and IBR developer, as applicable to the given
regulatory framework.
Certain IBR units (e.g., type III wind turbine generators [WTGs]) have been given different specifications
and requirements throughout this standard.
As a performance and not a design standard, this standard allows for alternate means of compliance as long
as all specified requirements are fulfilled at the reference point of applicability (RPA).
The requirements specified in this standard are intended to apply over the lifetime of the IBR plant. When
the TS operating and network conditions change significantly enough that changes in the IBR plant may
become necessary to reliably operate the IBR plant to support, or not degrade, TS reliability, equitable remedy
measures shall be coordinated between the TS owner and the TS operator, and the IBR owner and the IBR
operator. 15, 16
Where applicable, the stated technical specifications and requirements are given in generator sign convention,
which is opposite to load sign convention. In generator sign convention, an IBR current lagging voltage
provides/injects reactive power to the system (positive reactive power); an IBR current leading voltage
consumes/absorbs reactive power from the system (negative reactive power).
The following list describes what remains outside the scope of this standard:

How this standard is adopted or enforced in a specific regulatory context by the AGIR.

This standard intentionally does not define the system voltage levels for application of the
requirements of this standard, but leaves the applicability and enforcement of this standard at the
discretion of the AGIR.
Notes in text, tables, and figures of a standard are given for information only and do not contain requirements needed to implement
this standard.
15
Examples for significant TS operating and network condition changes are new plants interconnecting close to an IBR plant, installation
of new equipment by the TS owner, and changes in the short-circuit ratio (SCR) at the reference point of applicability.
16
Remedy measures may include IBR plant control parameter changes and hardware changes, as applicable.
14
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems

This standard intentionally does not define the size of plant, in terms of continuous active power
rating, for application of the requirements of this standard, but leaves the applicability and
enforcement of this standard at the discretion of the AGIR.

This standard as a whole is not intended for, and is in part inappropriate for, application to IBR
plant(s) where the RPA is at typical primary or secondary distribution voltage levels.

It is not the intent of this standard to limit the adoption of technologies and controls (e.g., grid
forming) that are currently being developed. At the time of writing of this standard, neither design
details, test data, nor technical literature is available to confirm that emerging technologies and
controls presently under research and development will be able to meet all specified requirements of
this standard. Due consideration should be given to the benefits of the new technology and controls
in deciding which requirements of this standard should be adopted and which may be exempted. This
should be done in coordination between IBR owner and TS owner/TS operator.

Various equipment (such as transformers, circuit breakers, switches, supplemental IBR devices,
communication equipment, etc.) in the IBR plant may be subject to standards outside the scope of
this standard, for example, IEEE Std C57.12.00 [B62], IEEE Std C57.12.80 [B63], IEEE Std C37.04
[B56], and IEEE Std C37.246 [B59]. 17

This standard does not define the maximum IBR capacity for a particular installation that may be
interconnected to a single point of interconnection (POI) or connected to a given TS.

This standard does not specify the scope and requirements for interconnection studies. Subject to a
specific regulatory context, the TS owner/TS operator should conduct an interconnection study in
coordination with the IBR owner that may include verification of requirements with this standard.

This standard does not specify capability and performance requirements for an IBR plant to provide
power oscillation damping controls. At the time of writing of this standard, power oscillation
damping controls are still emerging and standardization in terms of both capability and performance
is not practical. The TS owner/TS operator in mutual agreement with the IBR owner may require
power oscillation damping capability and specify performance requirements.

This standard does not apply to the non-IBR part of a hybrid plant or co-located plant. See Figure 3,
the definitions in 3.1, and B.3 for further details.

It is not the intent of this standard to limit the adoption of emerging use cases of synchronous
machines, for example, the use of a synchronous condenser as a supplemental IBR device to improve
the ride-through capability of an IBR plant under extreme contingency conditions. At the time of
writing of this standard, neither design details, test data, nor technical literature is available to confirm
that these emerging use cases (i.e., synchronous condenser as a supplemental IBR device) will be able
to meet all specified requirements of this standard, unless the synchronous condenser exceeds
applicable equipment standards, for example, IEEE Std C50.12™ [B60], IEEE Std C50.13 [B61],
and IEC 60034-3 [B30] for synchronous machines, including synchronous condensers, and
ANSI/NEMA MG-1 [B4] for motors and generators. Due consideration should be given to the
benefits and risks of the emerging use cases of synchronous machines in deciding which IBR plant
requirements of this standard should be adopted and which may be exempted. This should be done
in coordination between IBR owner and TS owner/TS operator not later than the IBR plant design
evaluation where capabilities and performance of a synchronous condenser are adequately
considered.

Any individual supplemental IBR device shall not be expected to meet any given performance
requirement specified by this standard on a standalone basis. The IBR plant (or the IBR unit[s], as
Some of the requirements in this standard are outside the normal ranges for components covered in applicable equipment standards,
such as voltage ranges, frequency ranges, ride-through requirements, and testing requirements. IBR units often have more capability
than non-IBR units with respect to many of these requirements. When designing an IBR plant, the various requirements and performance
limitations of all the equipment and supplemental IBR devices within an IBR plant needed to meet the requirements of this standard at
the IBR plant–level should be considered. In some cases, the requirements in this standard may require specifications for the
subcomponents that are more stringent than the present equipment standards. In other cases, the IBR plant design may be compliant to
this standard without changing the normal requirements of its integral components or supplemental IBR devices.
17
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
applicable) shall meet the given and all other requirements of this standard at the reference point(s)
of applicability. See Figure 3, the definitions in 3.1, and B.3 for further details. 18

Outside of the specific interconnection and interoperability requirements in the following clauses,
this standard does not prescribe IBR self-protection or any IBR operating requirements, as long as
these do not preclude the IBR from meeting the requirements of this standard. 19

This standard does not address planning, designing, operating, or maintaining the TS with IBR. That
also excludes any requirements or limitations to the deployment and configuration of protective
functions by the TS owner on their side of the interconnection system or at the POI. 20

This standard does not apply to interconnection or transfer schemes associated with load circuits on
the TS. Nor does it apply to transmission loading relief actions.

This standard does not give any normative guidance regarding how the TS operator or the TS owner
may specify functional parameter settings of an IBR, other than the default setting within the
specified ranges of available settings.

This standard does not address single-phase open conditions of IBRs.

This standard does not address effects of single-pole tripping and reclosing employed on TS on
performance of IBRs. The TS owner may specify additional performance requirements for
satisfactory operation of IBR plants during single phase tripping and reclosing events.

This standard does not address effects of increasing penetration of IBRs such as the impact of loss of
inertia, loss of fault duty, etc., as well as the impact of the intermittent and variable nature of certain
IBR generation types on reliability of the BPS.

Requirements for utilization—e.g., enabling a function or mode and the configuration of its control
parameters to deliver a specified performance—of any capabilities specified in this standard and
provision of the specified performance as a service are outside the scope of this standard and remain
in the purview of interconnection agreements and may be specific to the regulatory context as created
by the cognizant and responsible entity.

Other than specifying the provision and capability of secure communication at the IBR, this standard
does not determine the communication network specifics (e.g., architecture) nor the utilization of the
IBR provisions for an IBR interface capable of communicating (local IBR communication interface)
to support the information exchange requirements specified in this standard.

This standard does not address capability of IBR plants to remain in operation during environmental
conditions outside of the plant’s design basis. Examples include extreme temperature impacts on
mechanical or electrical components (including battery capacity and component ratings), extreme
wind impacts on mechanical or structural components, seismic impacts on mechanical, structural, or
electrical components, etc. The IBR owner shall inform TS owner/TS operator of any such
limitations.
Refer to footnotes 8 and 17; along with NOTE 5 in Figure 1; NOTE 1 to the definition of hybrid plant; NOTE 1 to the definition of
supplemental IBR device; as well as 4.1.4 and 4.1.5.
19
Requirements specified in 7.2.2 and 7.3.2 do provide constraints to be respected in the application of IBR self-protection.
20
When deploying and configuring the selectivity and sensitivity of such protective functions, the TS operators may need to coordinate
the protective functions to balance the reliability risk of wide-area tripping of IBR plants with the load balancing entity with the risk of
potential damage on the transmission system or sub-transmission system. This may include unintentional islanding protection schemes
deployed by the TS operator to prevent unintentional islanding of one or more IBR plant(s) connected to parts of the transmission system
or sub-transmission system that may become isolated unintentionally due to misoperation or unintended switching.
18
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 1—The POM is the default RPA. Moving the RPA from the POM to the POI may exceed the technical minimum
requirements specified in this standard and may require deliberate consideration of the pros and cons. For example, the
ability of IBR plants to meet the performance requirements in this standard may be impacted if the IBR owner is not
allowed to install their measurement and control equipment at the POI substation. 21
NOTE 2—The POC may be at either side of the IBR unit transformer, if present.
NOTE 3—A supplemental IBR device, e.g., reactive power compensation equipment, plant controller, and other
examples as listed in NOTE 1 of the definition in 3.1, may be used to achieve compliance with the requirements of this
standard at the RPA. In case where synchronous condenser is used as a supplemental IBR device, refer to a general
exemption in 1.4.
NOTE 4—More complex IBR connection setups that include multiple IBR tie lines to one or to multiple POIs in the TS
may be found in the practice for reliability or other reasons.
NOTE 5—Other electric generating units and equipment, e.g., synchronous condensers, synchronous generators with the
exception of synchronous generators connected to the TS via an inverter, and compensation that is not associated with
an IBR, are outside the scope of this standard.
Figure 1 —Illustration of defined terms for ac-connected inverter-based resources (IBRs)
21
Notes in text, tables, and figures of a standard are given for information only and do not contain requirements needed to implement
this standard.
23
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 1—This standard applies to isolated inverter-based resources (IBRs) interconnected via dedicated voltage source
converter (VSC) high-voltage direct current (HVDC) transmission facilities.
NOTE 2—This standard is not intended to apply to voltage source converter high-voltage direct current (VSC-HVDC)
connecting two ac interconnections with each other.
NOTE 3—This standard is not intended to specify requirements for VSC-HVDC that connect two buses within a
meshed/networked synchronous ac system.
NOTE 4—The requirements for cases where IBR are integrated with a multi-terminal VSC HVDC transmission schemes
may be specified by the TS owner.
NOTE 5—The requirements for cases where IBR and non-IBR are connected via VSC-HVDC, i.e., hybrid resource
facilities, may be specified by the TS owner.
Figure 2 —Illustration of defined terms for dc-connected isolated inverter-based
resources (IBRs)
NOTE—Conventional resource(s) include fossil fuel–driven generating units, hydro generating units, etc.
Figure 3 —Taxonomy of IBR and scope of IEEE Std 2800
24
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
1.5 Word usage
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). 22, 23
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).
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.
ANSI C84.1, Electric Power Systems and Equipment—Voltage Ratings (60 Hz). 24
IEC 61000-4-3, Electromagnetic compatibility (EMC)—Part 4-3: Testing and measurement techniques—
Radiated, radio-frequency, electromagnetic field immunity test. 25
IEC 61000-4-5, Electromagnetic compatibility (EMC)—Part 4-5: Testing and measurement techniques—
Surge immunity test.
IEC 61000-4-7, Electromagnetic compatibility (EMC)—Part 4-7: Testing and measurement techniques—
General guide on harmonics and interharmonics measurements and instrumentation, for power supply
systems and equipment connected thereto.
IEC 61000-4-15, Electromagnetic compatibility (EMC)—Part 4-15: Testing and measurement techniques—
Flickermeter—Functional and design specifications.
IEC 61000-4-30, Electromagnetic compatibility (EMC)—Part 4-30: Testing and measurement techniques—
Power quality measurement methods.
IEC 61000-6-2, Electromagnetic compatibility (EMC)—Part 6-2: Generic standards—Immunity for
industrial environments.
IEC/IEEE 60255-118-1, Measuring relays and protection equipment—Part 118-1: Synchrophasor for power
systems—Measurements.
IEC/IEEE 61850-9-3, Communication networks and systems for power utility automation—Part 9-3:
Precision time protocol profile for power utility automation.
22
The use of the word must is deprecated and cannot be used when stating mandatory requirements, must is used only to describe
unavoidable situations.
23
The use of will is deprecated and cannot be used when stating mandatory requirements, will is only used in statements of fact.
24
ANSI publications are available from the American National Standards Institute (https://www.ansi.org/).
25
IEC publications are available from the International Electrotechnical Commission (https://www.iec.ch) and the American National
Standards Institute (https://www.ansi.org/).
25
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
IEC TR 61000-3-7:2008, Electromagnetic compatibility (EMC)—Part 3-7: Limits—Assessment of emission
limits for the connection of fluctuating installations to MV, HV and EHV power systems.
IEEE Std 519™-2014, IEEE Recommended Practice and Requirements for Harmonic Control in Electric
Power Systems. 26, 27
IEEE Std 1453™-2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on Power
Systems.
IEEE Std 1588™, IEEE Standard for a Precision Clock Synchronization Protocol for Networked
Measurement and Control Systems.
IEEE Std 2030.101™, IEEE Guide for Designing a Time Synchronization System for Power Substations.
IEEE Std C37.90.1™, IEEE Standard Surge Withstand Capability (SWC) Tests for Relays and Relay
Systems Associated with Electric Power Apparatus.
IEEE Std C37.90.2™, IEEE Standard Withstand Capability of Relay Systems to Radiated Electromagnetic
Interference from Transceivers.
IEEE Std C37.238™, IEEE Standard Profile for Use of IEEE 1588™ Precision Time Protocol in Power
System Applications.
3. Definitions, acronyms, and abbreviations
3.1 Definitions
For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary
Online should be consulted for terms not defined in this clause. 28
active current priority mode: A mode in which the active current output (Ip) is given priority and has the
full current rating of the inverter-based resource (IBR) available to it (i.e., maximum current ac, Imax), while
the reactive current output (Iq) is constrained. The reactive current Iq range varies from a maximum of
(I
2
max
− I p2
)
to a minimum of −
(I
2
max
)
− I p2 , where Ip is the present value of active current. Syn: P-
Priority mode.
NOTE 1—The active current output (Ip) may be constrained by availability of energy source.
NOTE 2—For energy storage systems, the active current can be negative.
NOTE 3—The definition is written with focus on operation during a balanced fault or a system disturbance. During
unbalanced faults, the requirement to inject negative-sequence reactive current may further constrain active current and
positive-sequence reactive current output.
active power installed capacity (Pagg): The aggregate active power nameplate rating of the inverter-based
resource units (IBR units) within an IBR plant or hybrid plant.
actual active power (Pact, p): Instantaneous active power that an inverter-based resource plant (IBR plant)
is delivering to (or consuming from, as applicable) the transmission system (TS) as measured at the point of
measurement (POM). Syn: P; p.
26
The IEEE standards or products referred to in Clause 2 are trademarks owned by The Institute of Electrical and Electronics Engineers,
Incorporated.
27
IEEE publications are available from The Institute of Electrical and Electronics Engineers (http://standards.ieee.org/).
28
IEEE Standards Dictionary Online is available at: http://dictionary.ieee.org. An IEEE Account is required for access to the dictionary,
and one can be created at no charge on the dictionary sign-in page.
26
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 1—The Pact is limited by the IBR plant controller to the IBR continuous rating (ICR) for all steady-state operations.
NOTE 2—The Pact is limited by the IBR plant controller to the IBR short-term rating (ISR) during transient and dynamic
operations for a specific level of output and for a specific maximum time duration as specified in the interconnection
agreement.
apparent power installed capacity (Sagg): The aggregate apparent power nameplate rating of the inverterbased resource units (IBR units) within an IBR plant or hybrid plant.
applicable voltage: One of the electrical quantities that determine the basis of performance of an inverterbased resource (IBR). (Adapted from IEEE Std 1547™-2018)
NOTE—For this standard, applicable voltage is specified in 4.3.
applicable frequency: One of the electrical quantities that determine the basis of performance of an inverterbased resource (IBR). (Adapted from IEEE Std 1547™-2018)
NOTE—For this standard, applicable frequency is specified in 4.3.
authority governing interconnection requirements (AGIR): A cognizant and responsible entity that
defines, codifies, communicates, administers, and enforces the policies and procedures for allowing electrical
interconnection of an inverter-based resource (IBR) to the transmission system (TS). This may be a regulatory
agency, public utility commission, municipality, cooperative board of directors, etc., or depending on
jurisdiction, TS owner or TS operator. The degree of AGIR involvement will vary in scope of application
and level of enforcement across jurisdictional boundaries. This authority may be delegated by the cognizant
and responsible entity to the TS owner/TS operator or bulk power system operator. (Adapted from IEEE Std
1547™-2018)
NOTE—Decisions made by an authority governing interconnection requirements should consider various stakeholder
interests, including, but not limited to, load customers, TS operators, IBR operators, and bulk power system operators.
available active power (Pavl): Instantaneous ac active power that an inverter-based resource plant (IBR
plant) can deliver to (or consume from, as applicable) the transmission system (TS) subject to the availability
of the IBR’s primary energy source, IBR unit(s) nameplate ratings, and service status. (Adapted from IEEE
Std 1547™-2018)
NOTE 1—Examples of primary energy sources are solar irradiance in the case of a photovoltaic IBR, instantaneous wind
energy (determined by wind speed at a given moment) in case of a wind turbine generator, and state of charge in case of
a (battery) energy storage system.
NOTE 2—Individual IBR units and/or supplemental IBR devices may be out of service due to maintenance, failure, or
limited availability of the IBR’s primary energy source.
NOTE 3—An IBR’s operating mode (e.g., current priority mode: active or reactive) may limit the active power an IBR
delivers to a value below its available active power (P < Pavl).
NOTE 4—An IBR’s available active power (Pavl) can be greater or lesser than its IBR continuous rating (ICR), but not
greater than IBR short-term rating (ISR).
bulk power system (BPS): Any electric generation resources, transmission lines, interconnections with
neighboring systems, and associated equipment. (IEEE Std 1547™-2018)
NOTE—Per NERC glossary of terms, the definition of bulk power system is: (A) facilities and control systems necessary
for operating an interconnected electric energy transmission network (or any portion thereof); and (B) electric energy
from generation facilities needed to maintain transmission system reliability. The term does not include facilities used in
the local distribution of electric energy.
co-located plant: Two or more generation or storage resources that are operated and controlled as separate
entities yet are connected behind a single point of interconnection (POI). Syn: co-located power plant;
Contrast: hybrid plant.
NOTE 1—The resources of a co-located plant may require separate points of measurement (POMs) behind the single
POI.
27
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 2—The requirements of this standard only apply to the co-located inverter-based resource (IBR) plant(s). Other
standards’ requirements may be applicable to the co-located conventional generation resources and co-located non-IBR
energy storage system (ESS).
NOTE 3—Refer to Figure B.8, Figure B.9, and Figure B.10 for further details.
collector system: Equipment and systems utilized in the aggregation of inverter-based resource (IBR) units.
This includes many types of electrical equipment such as switch-gear, cables, lines, transformers, and reactive
compensating devices between the point of connection (POC) of IBR units and the point of measurement
(POM).
continuous operation: Exchange of current between the inverter-based resource (IBR) and a transmission
system (TS) within prescribed behavior while connected to the TS and while the applicable voltage and the
applicable frequency is within specified parameters. (Adapted from IEEE Std 1547™-2018)
NOTE—This is an IBR operating mode that is most often associated with “normal conditions.”
continuous operation region: The performance operating region corresponding to continuous operation.
(IEEE Std 1547™-2018)
current blocking: Temporary blocking of controlled exchange of current with transmission system (TS),
while connected to the TS, in response to a disturbance of the applicable voltages, with the capability to
immediately restore output of controlled current exchange when the applicable voltages return to within
defined ranges. Syn: momentary cessation
NOTE 1—Passive elements like filters, capacitor banks, etc., may continue to exchange current with TS.
NOTE 2—A directly-connected machine, e.g., type III wind turbine generator (WTG), cannot block current. However,
for a bolted three-phase fault on a radial connection to an inverter-based resource (IBR) plant consisting of type III WTGs,
which decouples the grid voltage from the type III WTG terminal voltage, rotor and grid-side converters may eventually
cease operation and the stator may also eventually cease to inject current due to loss of excitation.
NOTE 3—In IEEE Std 1547™-2018 the synonym for current blocking is momentary cessation.
disturbance period: The period of time during which the applicable voltage or the applicable frequency is
outside the continuous operation region. (IEEE Std 1547™-2018)
NOTE—A disturbance may not be the only reason for non-continuous operation. Other reasons could be transient or
short term operation.
energy storage system (ESS): System that is capable of absorbing energy, storing it, and dispatching the
energy into the power system. (IEEE Std 1662™-2016, with the word “back” deleted to provide more
flexibility for co-located energy resources)
NOTE—The ESS may absorb energy from the power system or any co-located energy resource.
enter service: Begin continuous operation of the inverter-based resource (IBR) with an energized
transmission system (TS). (Adapted from IEEE Std 1547™-2018)
fast frequency response: Active power injected to the grid in response to changes in measured or observed
frequency during the arresting phase of a frequency excursion event to improve the frequency nadir or initial
rate-of-change of frequency.
flicker: The subjective impression of fluctuating lighting luminance caused by voltage fluctuations in the
supply voltage. (Adapted from IEEE Std 1547™-2018)
NOTE—Above a certain threshold, flicker becomes annoying. The annoyance grows very rapidly with the amplitude of
the fluctuation. At certain repetition rates even very small amplitudes can be annoying (IEEE Std 1453™).
28
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
hardware-in-the-loop (HIL): A simulation method that allows a hardware under test (HUT) to interact in a
closed loop with a model under test (MUT).
hybrid plant: A generating or storage facility that is composed of multiple types of resources or energy
storage systems controlled and operated as a single resource behind a single point of interconnection (POI).
Syn: hybrid power plant; Contrast: co-located plant.
NOTE 1—The resources in a hybrid plant may include conventional electric generating units (such as fossil fuel–driven
synchronous generators and hydro-electric generation), and inverter-based resources (such as wind, solar photovoltaic
[PV], and energy storage systems). Examples for other equipment in a hybrid resource includes synchronous condensers
and compensation not part of the inverter-based resource (IBR) plant(s).
NOTE 2—The requirements of this standard only apply to the IBR plant(s) in a hybrid plant. Other standards’
requirements may be applicable to the conventional generation resources.
NOTE 3—The generating or storage facilities may have a single main transformer with a common point of measurement
(POM) and POI to facilitate operations as a single resource, but separate reference points of applicability (RPAs) may be
required for the IBR generating or storage facilities and the conventional generating facilities to facilitate measurement
of compliance to applicable standards.
NOTE 4—Refer to Figure B.7 for further details.
hybrid IBR plant: A hybrid plant that is composed of only inverter-based resources (IBRs) and/or energy
storage systems. Syn: mixed IBR plant.
NOTE 1—A common hybrid IBR plant combines renewable energy (solar photovoltaic [PV] or wind) and energy storage
systems.
NOTE 2—The requirements of this standard apply to both ac-coupled hybrid IBR plants (couples each form of generation
or storage at a common collection bus after it has been converted from dc to ac at each individual inverter) and dc-coupled
hybrid IBR plants (couples both sources at a dc bus that is tied to the grid via a dc-ac inverter).
NOTE 3—Refer to Figure B.5 and Figure B.6 for further details.
instantaneous: A qualifying term indicating that no delay is purposely introduced in the action of the device.
(IEEE Std C37.20.10™-2016)
NOTE—The inverter-based resource (IBR) response to changes of the applicable frequency or the applicable voltages
may be intentionally or unintentionally delayed due to IBR measurements or IBR controls. For the purpose of this
standard, the specified IBR performance requirements can inform pass/fail criteria of conformance test and verification
procedures in other documents, irrespective of the internal design of IBR measurements and controls.
interconnection: The result of the process of adding an inverter-based resource (IBR) to a transmission
system (TS), whether directly or via an intermediate ac IBR tie line. (Adapted from IEEE Std 1547™-2018)
NOTE—In case of IBR that interconnect to the TS via a dedicated radial voltage source converter high-voltage direct
current (VSC-HVDC) transmission facility, that facility is considered as part of the IBR plant and the above definition
equally applies.
IBR continuous rating (ICR): The steady-state, continuous active power rating of an inverter-based
resource (IBR) plant or hybrid IBR plant registered by the IBR owner at the transmission system (TS)
operator’s or authority governing interconnection requirements (AGIR)’s registry.
NOTE 1—The ICR is typically specified in the interconnection agreement. Many of the technical minimum capability
requirements in this standard refer to the ICR, for example, minimum reactive power capability and frequency response.
NOTE 2—The IBR plant operates at or below the ICR for all steady-state conditions. For a hybrid IBR plant, ICR may
be the aggregate maximum simultaneous active power total output; the maximum power output of each contributing
resource is independent of ICR.
29
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 3—Registered active power is often the magnitude of the steady-state maximum active power the IBR can inject
(or consume, as applicable) at the reference point of applicability (RPA) based on the TS interconnection limit or the IBR
active power installed capacity, whichever is less. Consider these three examples where the TS interconnection limit is
100 MW: (1) where a solar photovoltaic (PV) plant has an active power installed capacity of 50 MW, then ICR is 50 MW;
(2) where a solar PV plant has an active power installed capacity of 120 MW, then ICR is 100 MW; (3) where a hybrid
IBR plant combines an energy storage system of 50 MW and a solar PV plant of 80 MW, then ICR is still 100 MW due
to the TS interconnection limit.
NOTE 4—The ICR should be verified by studies of the TS before interconnecting the IBR plant to confirm that thermal,
voltage, and stability limits of the TS will not be violated.
NOTE 5—In cases where the active power installed capacity of an IBR plant or a hybrid IBR plant is greater than the
ICR, the available active power can, at times, also be greater than the ICR. Examples are solar PV and wind power plants
where IBR units are added to increase the capacity factor of the power plant. 29 The addition of energy storage systems
within a hybrid IBR plant can further increase its active power installed capacity and capacity factor. Note that while
adding dc resource capacity to an IBR plant may increase its capacity factor, it may not increase its active power installed
capacity because the ac active power nameplate rating of the IBR units may not change.
NOTE 6—Refer to Figure 4 for further illustration of relationship between ICR, active power installed capacity (Pagg),
IBR short-term rating (ISR), available active power (Pavl), and actual active power (Pact).
Figure 4 —Relationship between inverter-based resource active power terms
IBR continuous absorption rating (ICAR): The steady-state, continuous active power absorption rating of
an inverter-based resource (IBR) plant registered by the IBR owner at the TS operator’s or AGIR’s registry.
NOTE—ICAR applies to a hybrid plant, hybrid IBR plant, and energy storage systems.
IBR short-term rating (ISR): The temporary, short-term active power rating of an inverter-based resource
(IBR) plant or hybrid IBR plant registered by the IBR owner at the TS operator’s or AGIR’s registry.
NOTE 1—Not all IBR may have an ISR greater than their ICR, i.e., the ISR is not a technical minimum capability
requirement specified in this standard.
NOTE 2—Where the ISR is greater than the ICR, it may be used to accommodate services such as primary frequency
response and/or fast frequency response as agreed to and specified in the interconnection agreement.
NOTE 3—The ISR may be a single level of output for a specified maximum time duration, e.g., 15 min to 30 min, in
some cases only a few seconds, to accommodate under-frequency events, or may be specified as a power-versus-time
curve.
By increasing the overall energy production capacity of the facility, the resource can operate at its maximum allowable output (per
the interconnection agreement) over additional hours of the day.
29
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE 4—The ISR may be verified by studies of the TS before interconnecting the IBR plant to confirm that thermal,
voltage, and stability limits of the system will not be violated.
interconnection study: A study conducted during the interconnection process.
NOTE 1—An interconnection study may be conducted by the TS owner/TS operator, the inverter-based resource (IBR)
owner, or a third party and may require coordination between parties, subject to regulatory context.
NOTE 2—An interconnection study may include verification of requirements with this standard.
interconnection system: Individual or multiple devices that connect a main inverter-based resource (IBR)
transformer to the transmission system (TS) that are used exclusively to export power from, or exchange
power with, an IBR plant.
NOTE—This may include an IBR tie line.
IBR tie line: Equipment and systems that connect the point of measurement (POM) of an inverter-based
resources (IBRs) to the point of interconnection (POI) at the transmission system (TS) and that are used
exclusively to exchange power with an IBR plant. (Adapted from NERC PRC-025 with some changes)
NOTE—This includes protective functions.
IBR unit: See: inverter-based resource unit.
in service: See: service status.
interface: An electrical or logical connection from one entity to another that supports one or more energy or
data flows, respectively, implemented with one or more power or data links, respectively. (Adapted from
IEEE Std 1547-2018™)
interoperability: The capability of two or more networks, systems, devices, applications, or components to
externally exchange and readily use information securely and effectively. (IEEE Std 2030™ [B54], IEEE Std
1547™-2018)
inverter: A power electronic unit that changes direct-current power to alternating-current power. (Adapted
from IEEE Std 1547™-2018)
inverter-based resource (IBR): Any source of electric power that is connected to the transmission system
(TS) via power electronic interface, and that consists of one or more IBR unit(s) capable of exporting active
power from a primary energy source or energy storage system to a TS. A collector system or a supplemental
IBR device that is necessary for compliance with this standard is part of an IBR. See also: IBR plant; IBR
unit.
NOTE 1—See Figure 1.
NOTE 2—The term IBR dedicates any parts that are within the scope of this standard, including, but not limited to, IBR
unit, IBR plant, and supplemental IBR device. It can refer to hybrid IBR plants, the IBR parts of co-located plants, and
energy storage systems (ESS).
inverter-based resource developer (IBR developer): See: IBR owner.
inverter-based resource generating facility (IBR generating facility): See also: inverter-based
resource plant.
inverter-based resource plant (IBR plant): A grouping of one or more IBR unit(s) and possibly
supplemental IBR device(s) operated by a common facility-level controller along with a collector system to
achieve the performance requirements of this standard at a single reference point of applicability (RPA). Syn:
IBR generating facility.
NOTE—Does not include the IBR tie line.
31
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
inverter-based resource operator (IBR operator): The entity that is functionally responsible for
monitoring and operating the inverter-based resource through the local IBR communication interface.
NOTE—The IBR operator could be, for example, a utility, a load balancing entity, transmission system operator, or
another third party.
inverter-based resource owner (IBR owner): The entity that owns and is functionally responsible for the
maintenance of the inverter-based resource.
NOTE 1—For simplicity, this standard does not differentiate between the IBR owner and the entity that develops an IBR.
NOTE 2—For the purpose of this standard, the IBR owner is the entity that requests the interconnection of an IBR plant
with the transmission system.
inverter-based resource unit (IBR unit): An individual inverter device or a grouping of multiple inverters
connected together at a single point of connection (POC).
NOTE 1—Can be type tested by a verification entity to verify performance at the POC.
NOTE 2—An IBR unit may include a unit transformer.
NOTE 3—For type III wind turbine generators, the wind turbine itself, the doubly-fed generator, the rotor-circuit
inverter, and the three-winding unit transformer, if present, make up an IBR unit.
NOTE 4—A string inverter or set of string inverters that are type tested by a verification entity at a single POC is regarded
as an IBR unit for the purpose of this standard. A set of string inverters not type tested as a group is not regarded as one
IBR unit.
load balancing entity: The entity that is functionally responsible for integrating resource plans ahead of
time, maintaining load-interchange-generation balance within a balancing area, and supporting
interconnection frequency in real time.
NOTE—This term is defined because the transmission system (TS) operator is not responsible for obtaining and
specifying performance of primary frequency response and fast frequency response.
local IBR communication interface: An interface at the edge of the inverter-based resource (IBR) plant
capable of communicating to support the information exchange requirements specified in this standard for
all applicable functions that are supported in the IBR plant. (Adapted from IEEE Std 1547™-2018)
main IBR transformer: One or more high-voltage transformer(s) that step(s) up the inverter-based resources
(IBRs) collector system voltage to the transmission system (TS) voltage at the point of measurement, or in
the case of voltage source converter high-voltage direct current (VSC-HVDC), steps up or down the voltage
of the converter to the TS voltage at the point of measurement.
mandatory operation: Required continuance of active current and reactive current exchange of inverterbased resources (IBRs) with transmission system (TS) as prescribed, notwithstanding disturbances of the TS
voltage or frequency having magnitude and duration severity within defined limits. (Adapted from IEEE Std
1547™-2018)
NOTE—An IBR operating mode required during a disturbance period.
mandatory operation region: The performance operating region corresponding to mandatory operation.
(IEEE Std 1547™-2018)
NOTE—This concept equates to the term no trip zone as used in NERC PRC-024.
manufacturer stated measurement accuracy: Accuracy declared by the manufacturer, at which inverterbased resource (IBR) units and systems measure the applicable voltage, current, power, frequency, or time.
(Adapted from IEEE Std 1547™-2018)
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
maximum current ac, Imax: Value of current for the operating temperature range that should not be
exceeded. (IEEE Std C62.39™-2012)
NOTE 1—Modified from IEC 62319-1:2005 [B38]. May also be referred to as “rated current (Irated)” in this standard
based on apparent power rating.
NOTE 2—Imax can vary based on operating mode.
NOTE 3—The current limit of an inverter-based resource (IBR) unit is usually greater than or equal to 1.0 per unit (p.u.).
may trip operation region: The performance operating region where inverter-based resource (IBR) unit
protection is undefined by this standard and is determined only by IBR unit capability limits.
minimum active power capability (pmin): The minimum active power output of an inverter-based resource
(IBR) plant or a hybrid IBR plant registered by the IBR owner at the TS operator’s or AGIR’s registry in per
unit (p.u.) of the IBR continuous rating (ICR).
NOTE 1—Pmin may be determined by IBR characteristics, interconnection agreement, or other constraints.
NOTE 2—Pmin may be zero for some IBR plants, and for IBR that are capable of absorbing active power Pmin may be
negative.
mixed inverter-based resource (IBR) facility: See also: hybrid IBR plant.
momentary cessation: See: current blocking.
nameplate ratings: Nominal voltage (V), maximum current (A), maximum active power (kW), rated
maximum volt-amps or apparent power (kVA), and nominal frequency (Hz) that an IBR unit, supplemental
IBR devices, main IBR transformer, or any other equipment in an IBR plant that has a physical “plate,”
located on the equipment, is capable of sustained operation under defined ambient (temperature, humidity,
etc.) and site (e.g., altitude) conditions. (Adapted from IEEE Std 1547™-2018)
offshore IBR plant: An inverter-based resource plant that has at least one IBR unit with a support structure
that is subjected to hydrodynamic loading.
NOTE—Modified from IEC 61400-3-1:2019 [B36].
operating mode: Mode of inverter-based resource (IBR) operation that determines the performance during
normal or abnormal conditions. (Adapted from IEEE Std 1547™-2018)
out of service: See: service status.
overshoot: The maximum system output minus the final settled value, divided by the actual change in system
output (i.e., from its initial value to the final settled value), when the final settled value is within the defined
settling band, expressed as a percentage. See also: step response.
NOTE—A system quantity may increase or decrease and the required change in system output may be positive or
negative. Thus, the term maximum does not indicate a specific direction of a value change.
P-Priority mode: See also: active current priority mode.
percent of (%): See: per unit (p.u.).
performance operating region: A region bounded by point pairs consisting of magnitude (voltage or
frequency) and cumulative time duration which are used to define the operational performance requirements
of the inverter-based resources (IBRs). (Adapted from IEEE Std 1547™-2018)
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
permissive operation: Operating mode where the inverter-based resource (IBR) (either the IBR plant or an
IBR unit) performs ride-through in mandatory operation or in current blocking, in response to a disturbance
of the applicable voltages. (Adapted from IEEE Std 1547™-2018)
NOTE—In IEEE Std 1547-2018, permissive operation may also be a response to a disturbance of the applicable
frequency; and momentary cessation is a synonym for current blocking in this standard.
permissive operation region: The performance operating region corresponding to permissive operation.
(IEEE Std 1547™-2018)
permit service: A setting that indicates whether an inverter-based resource (IBR) is allowed to enter or
remain in service. (Adapted from IEEE Std 1547™-2018)
per unit (p.u.): Quantity expressed as a fraction of a defined base unit quantity. For active/reactive power
(active/reactive current), the base quantity is the appropriate active power (active current) value. For apparent
power (current), the base quantity is the appropriate apparent power (current) value. For frequency, the base
quantity is the nominal frequency (e.g., 60 Hz in North America). Quantities expressed in per unit can be
converted to quantities expressed in percent of a base quantity by multiplication with 100. (Adapted from
IEEE Std 1547™-2018) Syn: percent of (%).
NOTE—What defines the “appropriate” base quantity value depends on the context of a requirement in this standard.
Examples include i) the apparent power installed capacity (Sagg) of the IBR units within an inverter-based resource
(IBR) plant or hybrid plant, ii) the steady-state, continuous (active or apparent) power or current rating of an of an IBR
plant or hybrid IBR plant as they may be registered by the IBR owner at the TS operator’s or AGIR’s registry, and iii)
the maximum current ac (Imax) of an IBR unit.
point of interconnection (POI): The point where the interconnection system connects an inverter-based
resource (IBR) to the transmission system (TS).
NOTE 1—See Figure 1.
NOTE 2—The POI is similar to the point of interconnection as defined in IEEE Std C37.246™-2017 [B59] as a
“switching substation where a generation facility is electrically connected to a transmission system.”
NOTE 3—The POI is similar to the point of common coupling (PCC) as defined in IEEE Std 519™ where it is defined
as the “Point on a public power supply system, electrically nearest to a particular load, at which other loads are, or could
be, connected. The PCC is a point located upstream of the considered installation.”
NOTE 4—The POI in this standard is similar to the point of interconnection as defined by FERC for large generator
interconnection agreement (LGIA) and small generator interconnection agreement (SGIA) as “the point where the
interconnection facilities connect with the transmission provider’s transmission system.”
point of measurement (POM): A point between the high-voltage bus of the inverter-based resources (IBRs)
and the interconnection system. (Adapted from NERC Reliability Guideline—BPS connected inverter-based
resource performance [B75])
NOTE—The POM may be at the transmission system (TS) side terminals of the main IBR transformer, the connection
point of a supplemental IBR device, or the TS side of a protective device, whichever is closer to the IBR tie line.
point of connection (POC): The point where an inverter-based resource unit (IBR unit) is electrically
connected to a collector system, as specified by the IBR owner. Syn: terminal.
NOTE 1—See Figure 1.
NOTE 2—For (an) IBR unit(s) that are not self-sufficient to meet the requirements without (a) supplemental IBR
device(s), the point of connection is the point where the requirements of this standard are met by (an) IBR device(s) in
conjunction with (a) supplemental IBR device(s).
NOTE 3—The POC may be at either side of the IBR unit transformer, if present.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
post-disturbance period: The period starting upon the return of all applicable voltages or the applicable
frequency to the respective ranges of the continuous operation region. (Adapted from IEEE Std 1547™2018)
pre-disturbance period: The time immediately before a disturbance period. (Adapted from IEEE Std
1547™-2018)
primary energy source: Energy sources like solar irradiance in the case of a photovoltaic inverter-based
resource (IBR), instantaneous wind energy (determined by wind speed at a given moment) in case of a wind
turbine generator, and state of charge in case of a (battery) energy storage system.
protective function(s): A function within a protective device that detects defective lines or apparatus or
other defined power system conditions of an abnormal or dangerous nature to initiate appropriate control
action. (Adapted from IEEE Std C37.98™-2013 for “protective relay”) Syn: protection; protective device;
protection element.
NOTE—Could protect the inverter-based resource (IBR), interconnection system/IBR tie line, and/or the transmission
system (TS).
Q-Priority mode: See also: reactive current priority mode.
range of available settings: The range within which the inverter-based resource (IBR) has the capability to
adjust settings to values other than the specified default settings. (Adapted from IEEE Std 1547™-2018)
reaction time (Treact): The duration from a step change in a system quantity measured at a defined location
until the output of the system at the same defined location measurably changes in the direction of the control
effort. (Adapted from NERC Reliability Guideline—BPS connected inverter-based resource performance
[B75])
NOTE—Refer to Figure 5 for illustration of reaction time. Time between step change in system quantity and the time to
10 percent of required output change may be used as a proxy for determining this time.
reactive current priority mode: A mode in which the reactive current output (Iq) is given priority and has
the full current rating of the inverter-based resource (IBR) available to it (i.e, maximum current ac, Imax),
while the active current output (Ip) is constrained. The active current Ip range varies from a maximum of
(I
2
max
− I q2
) to a minimum of zero for generating IBR, and to − ( I
2
max
)
− I q2 for energy storage IBR, where
Iq is the present value of reactive current. Syn: Q-Priority mode.
NOTE 1—The Q-priority does not necessarily mean that active power (or active current) is reduced to zero. It just means
that the priority is given to reactive power (or reactive current).
NOTE 2—The definition is written with focus on operation during a balanced fault or a system disturbance. During
unbalanced faults, the requirement to inject negative-sequence reactive current may further constrain active current and
positive-sequence reactive current output.
reference point of applicability (RPA): The location where the interconnection 30 and interoperability
performance requirements specified in this standard apply. (Adapted from IEEE Std 1547™-2018)
regional reliability coordinator: The functional entity that is responsible for the reliable operation of the
bulk power system, has the wide area view of the bulk power system, and has the operating tools, processes
and procedures, including the authority to prevent or mitigate wide-area emergency operating situations in
both next-day analysis and real-time operations. (Adapted from IEEE Std 1547™-2018)
30
“Interconnection” is not be confused with the “interconnection agreement” with the connecting TS.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
NOTE—The regional reliability coordinator has the purview that is broad enough to enable the calculation of
interconnection reliability operating limits, which may be based on the operating parameters of transmission systems
beyond any transmission operator’s vision.
restore output: Return operation of the inverter-based resources (IBRs) to the state prior to the abnormal
excursion of voltage or frequency that resulted in a ride-through operation of the IBR. (Adapted from IEEE
Std 1547™-2018)
return to service: Enter service following recovery from a trip. (IEEE Std 1547™-2018)
ride-through: Ability to withstand voltage or frequency disturbances inside defined limits and to continue
operating as specified. (IEEE Std 1547™-2018)
rise time (Trise): The time for the output of a system to go from 10% to 90% of required output change.
(Adapted from IEEE Std 1241™-2010) See also: step response; step response time.
NOTE—Refer to Figure 5 for illustration of rise time.
secure/securely: Being in a state where all known cybersecurity risks are identified and managed either by
being mitigated with security controls or by being accepted by stakeholders.
service status: Operational state of equipment, an inverter-based resource unit (IBR unit), a supplemental
IBR device, or an IBR plant that determines whether it is in operation or out of operation. Status may be “in
service” or “out of service.” See also: in service; out of service.
NOTE—The service status of IBR units and/or supplemental IBR devices may determine the available active power and
reactive power capability of an IBR plant.
settling band: The region around the value change the system output is required to settle in after a step
change in a system quantity measured at a defined location. See also: settling time.
NOTE—Refer to Figure 5 for illustration of settling band.
settling time: The duration from a step change in a system quantity measured at a defined location until the
output of the system settles to within a specified settling band around its final value change at the same
defined location. (Adapted from IEEE Std 1031™-2011) See also: step response.
NOTE—Refer to Figure 5 for illustration of settling time.
solar photovoltaic system (solar PV): An inverter-based resource unit producing electrical energy from
solar radiation directly by photovoltaic effect. (Adapted from IEC 60050)
step response: The output of a system as a function of time t when the input is a step function of time t also.
(Adapted from IEEE Std 1547™-2018) See also: reaction time (Treact); rise time (Trise); settling time
(Tsettling); step response time; overshoot.
NOTE 1—Figure 5 (not to scale) defines terms that characterize a step response.
NOTE 2—A system quantity may increase or decrease and the required change in system output may be positive or
negative.
NOTE 3—The step response is used to describe the dynamic behavior of various specifications in this standard,
including, but not limited to, inverter-based resource (IBR) plant performance or measurements.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
(a) Dynamic performance metrics for a control reference step (e.g., frequency response, current
injection during fault); the figure illustrates a case where the required final value and final settled
value are equal.
(b) Dynamic performance metrics for a system quantity step (e.g., voltage regulation, power factor
regulation)
Figure 5 reprinted with permission from the Electric Power Research Institute (EPRI), © 2020.
Figure 5 —Step response characteristics and defined terms
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
step response time: The time between the step change in a system quantity measured at a defined location
and when the output of the system reaches 90% of required output change, before any overshoot. (Adapted
from IEEE Std 2745.1™, 2019) See also: rise time; step response.
sub-transmission system: See: transmission system (TS).
supplemental inverter-based resources device (supplemental IBR device): Any equipment within an
inverter-based resource (IBR) plant, which may or may not be inverter-based, that is only used to obtain
compliance with some or all of the interconnection requirements of this standard.
NOTE 1—Examples include equipment such as capacitor banks, STATCOMs, harmonic filters, protective devices, and
plant controllers, etc.
NOTE 2—In cases where synchronous condenser is used as a supplemental IBR device, refer to a general exemption in
1.4.
NOTE 3—Supplemental IBR devices may meet or exceed applicable equipment standards, as determined by an IBR plant
design evaluation (see 12.2.3).
total rated-current distortion (TRD): The non-fundamental frequency RMS current flowing (including
harmonics, interharmonics, and noise) between the transmission system (TS) and the inverter-based resource
(IBR) plant with respect to the rated RMS current capacity (Irated). (Adapted from IEEE Std 1547™-2018)
transmission system (TS): The transmission system that is connected to an inverter-based resource (IBR).
In this standard, the TS refers to both transmission and sub-transmission systems unless specific requirements
for each are different. Syn: sub-transmission.
NOTE 1—Typically, the TS owner has primary access to public rights-of-way, priority crossing of property boundaries,
etc., and is subject to regulatory oversight. See Figure 1.
NOTE 2—Sub-transmission systems may be operated or owned by a distribution utility or a vertically integrated utility.
transmission system operator (TS operator) 31: The entity that is functionally responsible for the operating
the transmission system.
NOTE—For sub-transmission systems, the responsible entity may be a distribution utility or a vertically integrated utility.
transmission system owner (TS owner): The entity that is functionally responsible for designing, building,
maintaining, and sometimes also planning the transmission system. Syn: TS planner.
NOTE 1—For simplicity, this standard does not differentiate between TS owner and the entity that plans a transmission
system.
NOTE 2—For sub-transmission systems, the responsible entity may be a distribution utility or a vertically integrated
utility.
transmission system planner (TS planner): See: TS owner.
type test: A test of one or more devices manufactured to a certain design to demonstrate, or provide
information that can be used to verify, that the design meets the requirements specified in this standard.
(Adapted from IEEE Std 1547™-2018)
unit transformer (or IBR unit transformer): A transformer that steps up the low/medium alternating
current (ac) voltage (typically 500 V to 1000 V, however, can be higher and in the medium-voltage range for
wind turbine generator units) at the terminals of an individual IBR unit up to the medium/high ac voltage
level of the collector system (typically 20 kV to 70 kV).
31
The TS operator term in this standard is equivalent to the term transmission operator (TOP) in the NERC glossary of terms.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
verification entity: A test or verification entity responsible for performing or observing type tests, inverterbased resource (IBR) evaluations, commissioning tests, post-commissioning test/verification, or overseeing
production testing programs to verify conformance of the IBR to the standard. (Adapted from IEEE Std
1547™-2018)
NOTE 1—Verification entities can be a transmission system (TS) owner, TS operator, IBR operator, IBR owner, IBR
developer, IBR unit manufacturer, or third-party testing agency, depending on the test or verification performed.
NOTE 2—In the United States, the verification entity for type tests may be a Nationally Recognized Testing Laboratory,
another independent third party, or the IBR unit manufacturer.
wind turbine generator (WTG): An inverter-based resource unit which converts the kinetic wind energy
into electric energy. (Adapted from IEC 60050)
NOTE 1—A wind turbine generator generally uses one of the following electric generator configurations: directconnected asynchronous generator (type I), asynchronous generator with external resistance control (type II), doubly-fed
generator (DFG) (type III), full-rated power converter (type IV), or direct-connected synchronous generator with
torque/speed converter (type V). For the purposes of this standard, only WTGs that use power electronic
inverters/converters for interconnection to the grid are considered (e.g., type III and type IV).
NOTE 2—Types III and IV are the most common configurations for modern wind turbine generators.
3.2 Acronyms and abbreviations
ac
alternating current
AGC
automatic generation control
AGIR
authority governing interconnection requirements
AVR
automatic voltage regulator
BPS
bulk power system
CSCR
composite short-circuit ratio
DFG
doubly-fed generator
DFT
discrete Fourier transform
EMI
electromagnetic interference
EMS
energy management system
EMT
electromagnetic transient
ESS
energy storage system
FACTS
flexible ac transmission systems
FERC
Federal Energy Regulatory Commission
FFR
fast frequency response
HIL
hardware-in-the-loop
HV
high voltage
HVDC
high-voltage direct current
IBGP
inverter-based generation plant
IBR
inverter-based resource
IBR operator
inverter-based resource operator
IBR owner
inverter-based resource owner
39
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
ICR
IBR continuous rating
Imax
maximum current ac
ISR
IBR short-term rating
MV
medium voltage
NERC
North American Electric Reliability Corporation
NRTL
nationally recognized testing laboratory
OEM
original equipment manufacturer
PLL
phase-locked loop
PFR
primary frequency response
POI
point of interconnection
POC
point of connection
POM
point of measurement
PV
photovoltaic
RMS
root mean square
ROCOF
rate of change of frequency
RPA
reference point of applicability
RVC
rapid voltage change
SCR
short-circuit ratio
SSCI
subsynchronous control interactions
SSO
subsynchronous oscillations
SSR
subsynchronous resonance
SVC
static var compensator
STATCOM
static synchronous compensator
THD
total harmonic distortion
TS
transmission system
TS operator
transmission system operator
TS owner
transmission system owner
TOV
transient overvoltage
TRD
total rated-current distortion
TVE
total vector error
OLTC
on-load tap changer
VSC
voltage source converter
VSC-HVDC
voltage source converter HVDC
WSCR
weighted short-circuit ratio
WTG
wind turbine generator
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
4. General interconnection technical specifications and performance
requirements
4.1 Introduction
The technical minimum requirements for the interconnection, capability, and performance in this standard
are specified for the IBR plant, unless otherwise stated. Where specified, certain requirements apply to one
or multiple IBR unit(s) within an IBR plant. The IBR plant may use supplemental IBR device(s) to achieve
compliance with the requirements of this standard. Refer to 4.1.4 for details on applicability of requirements
to supplemental IBR device(s).
The capabilities and functions of the IBR units, systems hardware, and the controls software that affect the
TS are required to meet this standard at the reference point of applicability (RPA) regardless of their location
on the TS. The performance requirements in this standard are functional and do not specify any particular
equipment or equipment design.
The capability and performance requirements specified here are universally needed for interconnection and
interoperability of an IBR plant and will be sufficient for most installations. 32 The applicability of certain
specifications and requirements depend on application considerations. An IBR plant shall be designed and
installed such that it meets the performance, test, and verification requirements described in Clause 4 through
Clause 12 of this standard. The interoperability requirements are specified in 4.5 and 4.6.
4.1.1 Coordination and specification of applicability
This standard does not specify TS operating and network conditions for which the requirements of this
standard shall apply at the time of interconnection or over the foreseeable future considering anticipated
system changes.
NOTE—To adequately design the IBR plant, the IBR owner may need sufficient information about TS operating and
network conditions for which all of the requirements specified in this standard shall apply without any exceptions. This
information helps to bound the engineering design problem and to clarify TS owner/TS operator’s expectations to IBR
plant performance under different TS operating and network conditions. This information may also help limit remedial
actions by the TS owner/TS operator for contingencies or other TS conditions, for example, the temporary limitation of
an IBR plant’s permissible active power output.
Subject to regulatory requirements, the TS owner/TS operator, in coordination with the IBR owner, should
specify reasonable TS operating and network conditions for which the requirements of this standard shall
apply at the time of interconnection and, as practical, over the foreseeable future considering anticipated
system changes. This may include some or all data recommended in the informative Annex H.
Upon request from the IBR owner/IBR developer, the TS owner/TS operator should provide the necessary
TS network data for expected operating conditions to the IBR owner/IBR developer to design the IBR plant.
Typical TS network data necessary for IBR plant design is noted in the informative Annex H.
4.1.2 Registration of IBR plant with TS operator
During the interconnection process, the IBR owner should register the IBR continuous rating (ICR) and, if
applicable, the IBR short-term rating (ISR) with the TS operator or the authority governing interconnection
requirements (AGIR). For IBR plants with energy storage systems (ESS), the IBR owner should also register
the IBR continuous absorption rating (ICAR). The TS operator may require additional registration values
from the IBR owner.
32
Additional technical requirements may be necessary for some limited situations.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
The TS operator should verify the acceptability of the ICR, and as applicable the ISR, by studies of the TS
before interconnecting the IBR plant to confirm that thermal, voltage, and stability limits of the TS system
will not be violated.
Once the IBR plant is operational, modifications to controls that change the response of the IBR plant or IBR
units as defined within this standard shall be mutually agreed upon between the TS operator and the IBR
owner.
NOTE 1—Many of the technical minimum capability requirements in this standard refer to the ICR.
NOTE 2—Not all IBR plants may have an ISR greater than their ICR, i.e., the ISR is not a technical minimum capability
requirement specified in this standard.
Additional data may be exchanged between the IBR owner and the TS operator considering the informative
Annex H as a guidance.
4.1.3 Impact of IBR unit(s) and supplemental IBR device(s) service status
Where the service status of individual IBR units and/or supplemental IBR devices within an IBR plant is out
of service, the IBR plant’s capability and performance may become less than those specified for ICR, ICAR,
or ISR. 33 In cases where this leads the IBR plant to become temporarily non-compliant with any part of this
standard, remedy shall be taken in coordination with the TS operator, regional reliability coordinator, and/or
load balancing entity. 34
NOTE—Refer to 1.4 for general remarks and limitations with regard to utilization of any capabilities specified in this
standard and provision of the specified performance as a service.
4.1.4 Supplemental IBR devices
Supplemental IBR devices other than IBR units may be used to achieve compliance with the requirements of
this standard at the applicable reference point per 4.2. These devices are not required to be co-located with
the IBR units, but shall be within the associated IBR plant. The requirements of this standard shall be met
regardless of the location of the IBR units and supplemental IBR devices within the IBR plant. These
relationships are shown in Figure 1 for ac-connected IBR and in Figure 2 for dc-connected IBR.
Supplemental IBR devices shall meet or exceed technical minimum requirements specified in applicable
equipment standards, as determined by an IBR plant design evaluation (see 12.2.3) to help ensure the IBR
plant meets all requirements of this standard. 35 An individual supplemental IBR device shall not be expected
to meet any given performance requirement specified by this standard on a standalone basis, as long as the
IBR plant or the IBR unit(s), as applicable, can meet that and all other requirements of this standard at their
respective reference point(s) of applicability. 36
Exception (as specified in 1.4): During the interconnection process, in cases where a synchronous machine,
e.g., synchronous condenser, is used as a supplemental IBR device and that may result in the IBR plant or
IBR unit being unable to meet all requirements of this standard, due consideration should be given to the
benefits and risks of the emerging use cases of synchronous condensers in deciding which requirements of
For example, this could be the case during periods of scheduled or unscheduled maintenance, or as a result of failure of an IBR unit
or supplemental IBR device.
34
If necessary, such remedy measures may range from temporarily taking an IBR plant out of service to temporarily limiting an IBR
plant’s active power output.
35
The technical minimum requirements specified in these equipment standards may or may not be sufficient for a synchronous machine
to fulfil the purpose of a supplemental IBR device, that is to help the IBR plant obtain compliance with some or all of the interconnection
requirements of this standard.
36
A supplemental IBR device does not necessarily need to meet all requirements of this standard; however, it is required to meet the
requirements for its purpose in the electrical system that makes up the IBR plant. The plant, as a whole, is required to meet the standard
requirements. To that end, there may or may not be requirements above and beyond typical equipment standards for the supplemental
device. The plant designer should determine the specific requirements for various components that make up the IBR plant, and
communicate these to vendors of the supplemental devices in the device procurement stage. See also footnote 17.
33
42
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
this standard should be adopted and which may be exempted. This should be done in coordination between
IBR owner and TS owner/TS operator not later than the IBR plant design evaluation where capabilities and
performance of a synchronous condenser is adequately considered.
After commissioning, in cases where a supplemental IBR device is used to meet some or all of the
requirements specified in this standard but fails to operate, or its service status is “out of service” as specified
in 4.1.3, and where this results in the IBR plant or IBR unit to become non-compliant with this standard, the
IBR owner shall take adequate remedy measures in coordination with the TS operator, regional reliability
coordinator, and/or load balancing entity. 37
4.1.5 Hybrid and co-located resources
For a hybrid plant that includes IBR and non-IBR, the requirements of this standard shall only apply to the
IBR plant(s) or the hybrid IBR plant(s) in the hybrid plant. Other standards’ requirements may be applicable
to the conventional generation resources in the hybrid plant. Requirements for the hybrid plant that is
controlled and operated as a single resource shall follow good engineering practices. 38
Conventional generation resources in a co-located plant may comply with applicable standards.
NOTE—Synchronous machines, including synchronous condensers, that are separate, co-located, or in the non-IBR part
of a hybrid plant, and that are not essential for the conformance of the IBR part of a hybrid plant with this standard, are
not considered supplemental IBR devices, and therefore the requirements of this standard may not apply. For those
synchronous machines the applicable equipment standards may be used as technical minimum requirements. One
example for synchronous machines that are not considered supplemental IBR devices includes synchronous machines
that are installed by the TS operator with the objective of improving TS operating and network conditions (e.g., grid
performance) or stable operation of IBR plant(s) in grid areas with reduced source strength (defined by the TS driving
point impedance; e.g., “weak grid” conditions) or increased sensitivity (e.g., large variation or high rate-of-change in
system quantities).
Subclause B.3 provides examples for various types of hybrid resources.
4.2 Reference points of applicability (RPA)
4.2.1 RPA for ac-connected IBR
Except as otherwise stated in this standard, the reference point of applicability (RPA) for all technical
minimum requirements for the interconnection, capability, and performance requirements in this standard
shall be the point of measurement (POM) of the IBR plant as shown in Figure 1. 39 The interconnecting TS
owner/TS operator may adapt some or all performance requirements, as specified in this standard, and move
their respective RPA to another location, including the point of interconnection (POI). 40
NOTE 1—The electrical quantities referred to in this standard are those at the RPA, unless otherwise stated.
NOTE 2—Informative Annex B presents interconnection examples.
NOTE 3—For requirements in this standard that apply to an IBR unit, the respective subclause specifies the point of
connection (POC) as the RPA.
See footnote 34.
Inherent differences in types of resources or energy storage systems in a hybrid resource facility may be considered when specifying
capability and performance requirements. This standard specifies technical minimum requirements for IBR which may be more stringent
of what a non-IBR may be able to achieve.
39
Due to possibility of many different interconnection scenarios, it is impractical to develop performance requirements for RPA other
than POM in this standard.
40
In some cases, for example, where the main IBR transformer may be owned by the TS operator, the RPA may be moved to the lowvoltage side of the main IBR transformer.
37
38
43
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
4.2.2 RPA for dc-connected isolated IBR
For isolated IBRs that are interconnected to an ac transmission system (TS) via a dedicated voltage source
converter high-voltage direct current (VSC-HVDC) transmission facility, the VSC-HVDC transmission
facility is considered a part of the IBR plant as shown in Figure 2. As such, the RPA shall be located on the
ac side of the VSC-HVDC transmission facility that interconnects with the TS. The requirements of this
standard shall not apply to the isolated IBRs. An isolated IBR may serve as a supplemental IBR device that
is necessary for the IBR plant with VSC-HVDC to meet the requirements of this standard at the RPA.
4.2.3 RPA for all other cases
In addition to the applicability of this standard on isolated IBRs, a TS owner/TS operator may apply this
standard, in whole or in part, to hybrid resource facilities that include one or more non-IBRs and that are
interconnected via a dedicated VSC-HVDC transmission facility to the TS.
4.3 Applicable voltages and frequency
The applicable voltages are the voltages at the reference point of applicability (RPA). The applicable
frequency is the frequency at the RPA.
For TS designed for effective grounding, the applicable voltages shall be the phase-to-phase and phase-toground voltages. 41 For any other TS, the applicable voltages shall be the phase-to-phase voltages. 42
The applicable frequency is the fundamental-frequency component of the applicable voltages. The
applicable voltages shall be quantified as the fundamental-frequency phasor component values, unless
otherwise specified in this standard. 43
For voltage protection, if applicable, and voltage ride-through requirements in 7.2.2, the following shall
apply:

For low-voltage ride-through, the relevant voltage shall be the lowest magnitude fundamental
frequency phasor component of the applicable voltages at the RPA relative to the corresponding
nominal voltage.

For high-voltage ride-through, the relevant voltage shall be the greatest magnitude fundamental
frequency phasor component of the applicable voltages at the RPA relative to the corresponding
nominal voltage.
For transient overvoltage ride-through requirements in 7.2.3, the following shall apply:

For transient overvoltage ride-through, the relevant voltage shall be the greatest magnitude of the
instantaneous applicable voltages at the RPA relative to the corresponding nominal voltage.
For rate of change of frequency (ROCOF) ride-through requirements in 7.3.2.3.5, the ROCOF shall be the
average rate of change of frequency over an averaging window of at least 0.1 s.
The TS owner specifies the TS nominal voltage and nominal frequency at the RPA.
Most transmission systems are designed for effective grounding.
Some sub-transmission systems have other higher impedance grounding schemes.
43
Where the applicable voltages approach or exceed 1.2 p.u., fundamental-frequency phasor component may be insufficient and pointon-wave values may need to be used as specified in other parts of this standard.
41
42
44
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
4.4 Measurement accuracy
All parameters that shall be measured and retained by the IBR, 44 per requirements in Clause 11 for
performance monitoring and validation, shall meet or exceed the steady-state 45 and transient measurement
accuracy requirements specified in Table 1 and Table 2. The specified accuracy requirements also apply to
the derived quantities. 46 For a given parameter, the specified minimum accuracy requirement is applicable
within the specified range; outside this range accuracy may be relaxed, if necessary. Upon request by the TS
owner, the IBR owner shall state the actual accuracy values of such measurements and derived quantities in
the format of aforementioned tables.
This standard specifies no accuracy requirements for measurements and derived quantities that may impact
an IBR’s performance as it relates to the requirements specified in this standard. 47 Upon request by the TS
owner, the IBR owner shall state the manufacturer stated measurement accuracy, i.e., the actual steady-state
accuracy values of such measurements and derived quantities, in the format of Table 1; and for the actual
transient accuracy values of such measurements, and derived quantities, in the format mutually agreed upon
between the TS owner and the IBR owner.
Table 1 —Measurement and derived quantities accuracy requirements
for Clause 11—steady-state time framef
Minimum accuracya
Range
Voltagec, d
± 2.5%
0.5 per unit (p.u.) to 1.2 p.u.
Currentc, d
± 2.5%
0.2 p.u. to 1.2 p.u.
Frequencyb
± 0.010 Hz
0.80 p.u. to 1.1 p.u.g
± 5%
0.2 p.u. < P < 1.0 p.u.
± 5%
0.2 p.u. < Q < 1.0 p.u.
Parameter
Active powere
Reactive
powere
Measurement accuracy requirements specified in this table are applicable for voltage
THD < 2.5% and individual voltage harmonics < 1.5%. The THD calculation method
is based on IEEE Std 519™-2014.
b Accuracy requirement is applicable only for fundamental frequency and when the
positive-sequence voltage is greater than 10% of the nominal positive-sequence
voltage.
c Measurement accuracy requirements for power quality terms are specified in
Clause 11.
d Accuracy requirement is expressed as percent of nominal rated value, not of measured
value.
e Accuracy requirements for active and reactive power are expressed as percentage of
fundamental frequency nominal apparent power in either direction over the specified
range.
f Accuracy requirements may be useful for applications such as voltage control and
SCADA.
g 48 Hz to 66 Hz for 60 Hz systems, 40 Hz to 55 Hz for 50 Hz systems.
a
44
The IBR includes any equipment required to meet the interconnection performance and interoperability requirements of the standard,
including plant-level controls, protective relays, and measurement transducers.
45
Steady-state measurements may be used for providing monitoring information through a local IBR communication interface at the
reference point of applicability as specified in Table 1.
46
Only the fundamental parameters can actually be measured, e.g., time, voltage, and current. Other quantities are calculated based on
the fundamental parameters measured, e.g., frequency, active power, and reactive power.
47
Clause 12 specifies requirements to test and verify IBR performance. An IBR plant design evaluation may consider performance and
accuracy of IBR measurements and derived calculations as one of many other factors to meet the performance requirement specified in
this standard.
45
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Table 2 —Measurement and derived quantities accuracy requirements
for Clause 11—transient time framek
Parameter
Voltagec
Currentc, g
Frequencyh, i
Minimum
accuracya
± 10%d, e
±
10%d, e
± 0.010 Hz
Maximum
length of
sliding
window
1 cyclef
Maximum
resolutionb
Range
1/32 cycle
0.1 p.u. to 2.0 p.u.
cyclef
1/32 cycle
0.1 p.u. to 1.4 p.u.
6 cycles
1/4 cycle
0.80 p.u. to 1.1 p.u.j
1
Include sensor and measurement system accuracy.
sec can be calculated for 50 Hz and 60 Hz nominal frequency systems.
c Fundamental frequency component of phasor.
d Accuracy requirement is expressed as percent of nominal rated value, not of measured value.
e Accuracy value reflects total vector error (TVE). TVE definition is the same as in IEC/IEEE
60255-118-1; this standard requires different values of TVE as in Table 2. The use of TVE
definition from the IEC/IEEE 60255-118-1 does not mean that PMU measurements are required
for parameters in this table. The intent is to adopt the way magnitude and phase angle errors of
these parameters are calculated.
f Can include up to another ¼ cycle based on algorithm.
g Measurement shall be able to eliminate the effect of dc component.
h Fundamental frequency.
i Accuracy requirement for frequency is applicable only for fundamental frequency and when the
positive-sequence voltage is greater than 10% of the nominal positive-sequence voltage.
j 48 Hz to 66 Hz for 60 Hz systems, 40 Hz to 55 Hz for 50 Hz systems.
k Accuracy requirements may be useful for applications such as dynamic voltage support,
protection, and short-circuit contribution.
a
b Minimum sampling rate per
4.5 Operational measurement and communication capability
The IBR plant shall, in a secure way, 48 provide a local IBR communication interface with bi-directional
communication capability, and shall be capable of securely48 providing real-time operational information of
its status, mode of operation, and several steady-state, dynamic, and transient measurements. 49
Communication protocols 50 and data to be exchanged shall be defined in the interconnection agreement or
by the services the IBR plant is offering to those entities. Test or verification of these requirements shall be
mutually agreed upon between the TS operator and IBR operator.
The IBR owner/operator shall implement measures for availability, integrity, and confidentiality of all IBR
plant communication capability and protocols, and all data exchange with all operational entities, including
the TS operator. 51 Test or verification of these cyber security measures shall be mutually agreed upon
between the TS operator and IBR operator, in consideration of the applicable regulations and available
technologies regulations.48
4.6 Control capability requirements
The IBR plant shall be capable of responding to external control inputs. 52 Control parameters to be exchanged
shall be defined in the interconnection agreement or by the services the IBR plant is offering to applicable
For North American entities, the applicability to NERC CIP standards are listed in the informative bibliography in Annex A.
The operational information is intended to support integration into energy management systems (or distributed energy resource
management system—DERMS) of the TS operator, load balancing entity, regional reliability coordinator, and markets in which it
operates.
50
Examples for industry-accepted communication protocols may include IEEE Std 1815™ [B53] and IEEE Std 2030.5™ [B55].
51
This may include communication and data exchange between equipment within the IBR plant, as applicable. References to some
cybersecurity standards and guidelines is provided in Annex A.
52
The external input may come through a manual IBR control panel or through the IBR communication interface specified in 4.5.
48
49
46
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
entities. Test or verification of these requirements shall be mutually agreed upon between the TS operator
and IBR operator.
Examples for control capabilities include:

Capability to cease operation following disabling of the permit service setting within a time as
specified by the TS operator.

Capability to limit active power at a value below IBR continuous rating (ICR) within a time as
specified by the TS operator.
4.6.1 Execution of mode or parameter changes
Transition time between modes commencing after the mode-setting change is received at the local IBR
communication interface shall be as required by the TS operator. Changes of control functional modes shall
be executed such that the IBR plant output is transitioned smoothly over a period of time required by the TS
operator.
4.6.2 Ramping for control parameter change
Ramping or similar smooth transition of IBR plant output shall be required for control parameter setting
changes. For all control and protective function parameter settings, the time following the input to the IBR
communication interface and preceding the point in time when the invoked action begins shall be no greater
than required by the TS operator.
4.7 Prioritization of IBR responses
Requirements for IBR plant and IBR unit, respectively, set forth in Clause 5, Clause 6, and Clause 7 shall be
prioritized as follows: 53
a)
The IBR plant response to disabling permit service setting specified in 4.6 shall take precedence over
any requirements within Clause 5, Clause 6, and Clause 7.
b) Tripping of IBR plant or IBR unit to clear a fault condition either within the IBR plant or on the
interconnection system, including islanding condition, shall take precedence over any other
requirements within Clause 5, Clause 6, and Clause 7.
c)
IBR plant or IBR unit tripping due to self-protection of equipment may take precedence over any other
requirements within Clause 5, Clause 6, and Clause 7 when self-protection is necessary to reduce risk
of permanent damage or destruction of equipment. This does not remove the obligation of the IBR plant
to meet all requirements of this standard and may lead to non-compliance with this standard.
d) IBR plant ride-through requirements specified in 7.2.2, 7.2.3, and 7.3.2 shall take precedence over all
other requirements within Clause 5, and Clause 6.
e)
The IBR plant active-power/frequency response requirements specified in Clause 6 shall take
precedence over all other requirements within Clause 5, Clause 6, and Clause 7, with the exception of
requirements listed in above items.
f)
The IBR plant response to active power limit signal specified in 4.6 shall take precedence over all other
requirements within Clause 5, Clause 6, and Clause 7, with the exception of requirements listed in
above items.
g) The IBR plant reactive power/voltage control functions specified in Clause 5 shall take precedence over
any remaining requirements within Clause 5 and Clause 6.
53
Based on the actual settings of the control modes, a mode with lower priority may still take effect prior to a mode with higher priority.
47
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
4.8 Isolation device
When required by the TS operating practices, a readily accessible, visible-break isolation device shall be
located between the TS and the IBR plant, meeting the requirements of the TS owner. In case of gas-insulated
switchgear, alternate means may be permitted with mutual consultation with the TS owner. The isolation
device should be clearly marked to include signage per applicable codes.
4.9 Inadvertent energization of the TS
The IBR plant shall not energize the TS when the TS is de-energized. Exceptions may be given for blackstart IBR at the discretion of the TS operator.
4.10 Enter service
The requirements of this subclause shall be applicable only if specific connection or reconnection practices
are not otherwise specified by the TS operator.
4.10.1 Introduction
The enter service criteria for an IBR plant are specified in Table 3. The active power performance during
entering service is specified in 4.10.3. The requirements apply when:

Entering service after an IBR plant was out of operation, for example, when the primary energy
source is not available (e.g., during night, no wind periods), due to market conditions, or
maintenance, at the direction of the TS operator.

Returning to service at the direction of the TS operator as specified in 7.4 after an IBR plant trip, for
example, following self-protection due to an internal fault, or following an unsuccessful ridethrough. 54
The requirements in Table 3 are not intended to specify IBR plant capability to enter service for all applicable
voltage and applicable frequency values within the ranges of adjustable settings; these criteria only specify
necessary conditions for which an IBR plant is allowed to enter service.
4.10.2 Enter service and return to service criteria
When entering service or returning to service, the IBR plant shall not output active power to the TS until the
applicable voltage and applicable frequency are within the ranges specified in Table 3 and the permit service
setting is set to “Enabled.” The enter service criteria in Table 3 specify the conditions for which an IBR plant
is permitted to enter service; these criteria do not mandate any IBR plant to enter service or stay in operation
for the specified voltage and frequency conditions. The restrictions of this subclause shall not apply if the TS
operator specifically directs the IBR plant to enter service or return to service.
54
This could cause non-compliance with this standard.
48
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Table 3 —Enter service criteria for IBR plants
Enter service criteria
Permit service
When enabled
Default settingsc
Disabled
Ranges of available settings
Enabled/disabled
Applicable voltage
within range
Minimum value
Maximum value
Specified by TS operator
Specified by TS operator
0.90 p.u. to 0.95 p.u.a
1.05 p.u. to 1.10 p.u.b
Applicable
frequency within
range
Minimum value
Specified by TS operator
0.98 p.u. to 0.99 p.u.
(58.8 Hz to 59.4 Hz @ 60 Hz)
(49.0 Hz to 49.5 Hz @ 50 Hz)
Maximum value
Specified by TS operator
1.002 p.u. to 1.02 p.u.
(60.12 Hz to 61.2 Hz @ 60 Hz)
(50.1 Hz to 51 Hz @ 50 Hz)
an IBR plant connected to a weak grid, the minimum voltage value to enter service may be mutually agreed
upon between the IBR operator and the TS operator.
b Voltages above 1.05 p.u. may be outside the current interrupting capability of fault-interrupting devices rated
for maximum system voltage in accordance with ANSI C84.1.
c Enter service criteria should consider any limitations of various equipment inside the IBR plant.
a For
4.10.3 Performance during entering service
During entering service, the IBR plant shall be capable of the following:
a)
Prevent enter service when permit service setting is disabled.
b) The IBR plant shall be capable of delaying enter service by an intentional adjustable minimum delay
when the TS steady-state voltage and frequency are continuously within the ranges of available settings
specified in Table 3. The range of available settings of the minimum intentional delay shall be 0 s to
600 s with a default minimum delay as specified by the TS operator.
c)
The IBR plant shall increase output of active power, 55 or exchange of active power for energy-storageIBR, during enter service as specified. Active power shall increase approximately linearly with an
average rate-of-change not exceeding the IBR continuous rating divided by the enter service period.
The duration of the enter service period shall be adjustable over a range of available settings of 1 s to
1000 s with a default time as specified by the TS operator. 56 The maximum active power increase of
any single step during the enter service period shall be less than or equal to 5% of the IBR continuous
rating. Where a stepwise ramp is used, the average rate-of-change over the period from the beginning
of one step to the beginning of the next step shall not exceed the average rate-of-change over the full
enter service period. This requirement is a maximum ramp rate requirement and the IBR plant may
increase output at a slower rate than specified.
4.11 Interconnection integrity
4.11.1 Protection from electromagnetic interference (EMI)
An IBR unit, except for a WTG, shall be compliant with IEEE Std C37.90.2™, IEC 61000-4-3, or other
applicable industry standards with a minimum electric field strength of 30 V/m. 57 A WTG shall be compliant
with IEC 61000-6-2 or other industry standards applicable for WTG equipment.
55
For restore output of active power after return to service, direction of active power may be negative (charging) for energy storage
IBR, e.g., return to frequency reduction via charging through droop or dispatch control, if operating for that purpose prior to trip. This
requirement does not exclude use of alternate means to meet this requirement.
56
Base values for quantities expressed in per unit and percent of are specified in 3.1.
57
Information on references can be found in Clause 2.
49
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
The influence of EMI, having an electric field less than or equal to the value specified in this subclause, shall
not result in a change in state or misoperation of the IBR unit that affects performance required by this
standard.
4.11.2 Surge withstand performance
The interconnection system shall have the capability to withstand voltage and current surges in accordance
with the interconnection system ratings as specified by the TS owner. The protection, control, and
communication systems and devices shall have the capability to withstand voltage and current surges and
environments defined in IEEE Std C62.41.2™ [B64], IEEE Std C37.90.1™, IEEE Std C62.45-2002™ [B65],
or IEC 61000-4-5, as applicable.
4.11.3 Interconnection switchgear
Where used for isolation of an IBR plant or IBR unit that continuously produces voltage after isolation from
the TS, the isolating switchgear shall be capable of withstanding 220% of the IBR plant or IBR unit rated
voltage to accommodate voltages that are out of phase across the isolating device for an indefinite duration. 58
4.12 Integration with TS grounding
This standard does not specify any requirements for integration of grounding scheme between the IBR Plant
and the TS. The TS owner may specify requirements as appropriate.
58
The interconnection switchgear is required to be capable of withstanding 220% of nominal voltage across the isolating gap to
accommodate voltages that are out of phase with each other.
50
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
5. Reactive power-voltage control requirements within the continuous
operation region
5.1 Reactive power capability
The default reference point of applicability (RPA) for the minimum reactive power capability (Qmin)
requirements of an IBR plant shall be the point of measurement (POM). Alternate locations for the RPA, such
as the POI, may be specified by the TS owner. The minimum reactive power capability shall have following
characteristics within the continuous operation region as specified in 7.2 and 7.3:

An IBR plant shall have the capability to inject and absorb a minimum reactive power defined by
|Qmin | ≥ 0.3287 × ICR at the RPA when injecting active power into the TS. 59

An IBR plant shall have the capability to inject and absorb minimum reactive power defined by
|Qmin| ≥ 0.3287 × ICAR at the RPA when absorbing active power from the TS. The ICAR of an IBR
plant may be less than ICR.

Where an IBR plant’s minimum reactive power capability Qmin may be temporarily reduced due to
IBR units and/or supplemental IBR devices that are out of service, the coordination requirements set
forth in 4.1.3 shall apply.

The minimum reactive power capability shall be met at the RPA for all active power output levels
(including at zero) of the IBR plant as shown in Figure 6 and Figure 7 with the following exceptions:
a)
For an IBR plant consisting of type III WTGs that are not connected to the TS via a VSCHVDC line, the minimum reactive power capability requirement when the active power
output is less than 0.1 × ICR is reduced to as shown by the dashed line due to limitations of
the technology.
b)
For an ac-connected offshore IBR plant (refer to Figure B.2), the minimum reactive power
capability should be met at the RPA for all active power output levels (including at zero) of
the IBR plant as shown in Figure 6 and Figure 7, but exceptions may be mutually agreed
upon between the IBR owner and TS owner/TS operator; exceptions shall not require less
reactive power capability than is specified for type III WTG-based IBR plant as shown in
Figure 6.

The minimum reactive power capability for non-nominal voltage conditions is shown in Figure 8.

IBR units shall have the capability to provide reactive power support when the primary energy source
is available and not available, and during the transition between these two resource availability states.
IBR units shall have the capability to remain in service while not exporting or importing active power,
except for importation of active power to cover losses, and to have the reactive power capability as
defined as shown in Figure 6 and Figure 7. Note that the type III WTGs may have a reduced reactive
power capability when the primary energy source is not available due to the size of the line-side
converter. The utilization of this capability shall be under mutual agreement between the IBR owner
and the TS owner.

If the IBR owner and the TS operator have agreed that an IBR plant is allowed to cease operation
below a specified minimum active power capability (Pmin) that is greater than zero, the IBR plant will
not produce reactive power when the IBR plant has ceased operation.
59
The minimum reactive power coefficient of 0.3287 corresponds to a reactive power at active power 1.0 p.u. and a power factor of
0.95, i.e., (1.0*tan(acos(0.95)).
51
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Associated Transmission Electric Power Systems
ICR – IBR continuous rating
Qmin – minimum reactive power capability
NOTE 1—Exchange of reactive power may require the IBR plant to consume active power from the grid due to losses
when there is no available primary energy source.
NOTE 2—The figure shows the minimum range for the reactive power capability required by this standard. The IBR
plant’s actual capability may be outside of the black box.
Figure 6 —Minimum range for reactive power capability—Q versus P for active power
injection capability at the RPA (generator sign convention)
52
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Associated Transmission Electric Power Systems
ICAR – IBR continuous absorption rating
Qmin – minimum reactive power capability
Figure 7 —Minimum range for reactive power capability—Q versus P for
active power absorption capability at the RPA (generator sign convention)
Furthermore,

Minimum reactive power capability at the RPA for continuous and up to 30-min operation as required
in Figure 8 shall be met within the applicable default voltage range specified in Table 4. For an IBR
plant consisting of type III WTGs, the minimum reactive power capability requirement when the
voltage is less than 0.95 p.u. may be further reduced as shown in Figure 8 due to limitations of the
technology.

The IBR plant shall be capable to maintain the voltage schedule (within the reactive power capability
described previously) provided by the TS operator. IBR plants with storage that are capable of
absorbing power from the grid shall have this capability when discharging, charging and across the
transition from discharging to charging and vice versa unless otherwise instructed by the TS operator.
53
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Associated Transmission Electric Power Systems
Figure 8 —Minimum reactive power capability—Q versus V (generator sign convention)
NOTE 3—The figure combined with the default values specified in Table 4 illustrates minimum reactive power
capability. The TS owner may increase or decrease these requirements as needed.
Table 4 —RPA voltage rangea
V1
(p.u.)
0.90
V2
(p.u.)
0.99
V3
(p.u.)
1.03
V4
(p.u.)
1.05
V5
(p.u.)
1.10
0.90
1.00
1.04
1.05
1.10
500 kV
0.90
1.02
1.06
1.10
1.10
735 kVb
0.90
1.02
1.06
1.088
1.10
TS nominal voltage
at the RPA
< 200 kV
≥ 200 kV
except 500 kV and
735 kV as below
a
The TS operator may require different values for the above quantities.
The ANSI C84.1 does not include 735 kV as a standard nominal system voltage. Voltage ranges are based on an
assumption that equipment rated for 800 kV is applied, which would be typically used for standard nominal voltage of
765 kV.
b

Reactive power/current limiters shall only be utilized to protect equipment and/or personnel.

The minimum reactive power capability and control within the continuous operation region shall be
dynamic as defined by time response specifications in Table 5.
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Associated Transmission Electric Power Systems

The IBR plant’s time response following a steady-state condition is inclusive of any transformer tap
changing that is necessary to retain IBR unit voltages within the range for which their reactive power
capability is required. 60, 61

Reactive power compensation from power electronics based systems (e.g., the IBR units, static var
compensator [SVC], static synchronous compensator [STATCOM], etc.), and rotating machines
(e.g., synchronous machines and type III WTGs) shall be considered dynamic. Reactive power
compensation from synchronous machines shall be considered dynamic only if the excitation is
automatically controlled to meet the IBR plant reactive performance requirements, including
dynamic response.

Electronically-switched compensation devices (e.g., thyristor-switched capacitors) may be
considered dynamic and may be used to meet a portion of the required minimum reactive power
capability requirements if their switching is coordinated with variable reactive power sources such
that the net IBR plant reactive power output is continuously variable.

Reactive power from mechanically-switched reactive power compensation devices (e.g., shunt
capacitors and shunt reactors) shall not be considered dynamic. But such compensation devices may
be used to compensate for the reactive power losses between IBR units and the RPA. If non-dynamic
reactive power compensation devices are used to compensate for reactive power losses between IBR
units and the RPA, they shall be automatically controlled such that the IBR plant maintains the
minimum required dynamic reactive power capability. Mechanically-switched compensation device
switching shall be coordinated with the dynamic devices such that there are not significant
discontinuities or step changes in the net IBR plant reactive power.
5.2 Voltage and reactive power control modes
5.2.1 General
The IBR plant shall provide voltage regulation capability by changes of reactive power output whenever the
RPA voltage is in the continuous operation region for voltage. The voltage and reactive power control
functions do not create a requirement for the IBR plant to operate at points outside of the minimum reactive
power capabilities specified in 5.1.
The IBR plant shall provide the capabilities of the following mutually exclusive operating modes of reactive
power control functions:

Voltage control

Power factor control

Reactive power set point control
The IBR plant shall be capable of activating each of these modes one at a time. The RPA voltage control
mode shall be the default mode of the installed IBR plant unless otherwise specified by the TS operator.
The IBR operator shall be responsible for implementing setting modifications and mode selections, as
specified by the TS operator within a time acceptable to the TS operator.
Under mutual agreement between the TS operator and IBR operator, reactive power control modes and
implementations other than the ones listed above and described below shall be permitted.
60
Conventional transformer on-load tap changers may not be fast enough to meet the dynamic response requirements, thus possibly
making it necessary to meet the entire reactive range with fixed taps unless unconventional tap changer equipment is used.
61
Steady-state conditions means that OLTCs and VAR banks may be allowed to settle at their optimum position after any prior events
before a step change in voltage is initiated to measure response time.
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Associated Transmission Electric Power Systems
5.2.2 Voltage control
When in this mode, the IBR plant shall operate in closed-loop automatic voltage control mode to regulate the
steady-state voltage at the RPA to the reference value, as adjusted by the droop function, to within 1% of the
RPA voltage set point unless to do so requires reactive power exceeding the reactive power capability of the
IBR plant. The RPA voltage set point shall be specified by the TS operator.
The voltage control system shall be capable of reactive power droop to provide a stable and coordinated
response. The droop setting shall be settable and coordinated by the TS operator and IBR operator. The
automatic voltage control shall have a range of available droop settings from 0 to 0.3 per unit voltage change
for 1.0 per unit reactive power on the ICR base. The RPA voltage control settings are allowed to be adjusted
locally and/or remotely as specified by the TS operator. The dynamic reactive power response of the IBR
plant to a step change in the RPA voltage within the continuous operation region and within IBR plant’s
reactive power capability shall be as specified in Table 5. 62, 63 Dynamic performance requirements shall be
based on, and only applicable to, a defined range of TS equivalent impedance at the POM, specified by the
TS operator.
The response shall be stable and any oscillations shall be positively damped with a damping ratio of 0.3 or
higher. 64 Stable and damped response shall take precedence over response time. That is, if it is shown that
for the applicable IBR plant and the given grid to which the IBR plant is connected, stable response requires
a response time that is closer to the upper limit defined in Table 5, then this is preferred to provide stable and
damped response.
Table 5 —Performance target range
Parameter
Performance target
Notes
Reaction
time
< 200 ms
Maximum
step
response
time
As required by the TS
operator
The slowest response shall be tuned
based on the TS operator
requirements for response time and
stability given the anticipated range
of grid strength, other local voltage
control devices, and overshoot
requirements. The step response
time may typically range between 1 s
and 30 s. Any switched shunts or
LTC transformer tap change
operation needed to restore the
dynamic reactive power capability in
Figure 8 shall respond within 60 s.
Damping
Damping ratio of 0.3
or higher
Damping ratio, indicative of control
stability, depends on grid strength.
Depending on the IBR plant control architecture, the response to a voltage reference step may not be the same as the response to a
RPA voltage change due to changes in the TS or in the IBR plant active power flow.
63
It should be noted that if other dynamic devices are in the vicinity of the RPA of the plant under consideration, which have an apparent
power rating comparable or larger than the plant under consideration, then it is considered when evaluating the plant’s response.
64
Refer to informative Annex L for a discussion of damping ratio.
62
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Associated Transmission Electric Power Systems
5.2.3 Power factor control mode
When in this mode, the IBR plant shall have a reactive power output that is in linear proportion to the active
power, as to maintain reactive power output to within 5% of the IBR plant’s nominal apparent power rating
from the reactive power level equivalent to the power factor setting, for the actual active power output. The
target power factor shall be specified by the TS operator. The power factor settings are allowed to be adjusted
locally and/or remotely as specified by the TS operator. The power factor control mode shall appropriately
operate at all active power levels down to certain minimum IBR power level as specified by TS operator.
The dynamic response of the IBR plant to any changes in power factor (e.g., due to a step change in active
power) shall be positively damped with a damping ratio of 0.3 or better.
5.2.4 Reactive power control mode
When in this mode, the IBR plant shall maintain a specified constant reactive power output at the RPA to
within a tolerance of 5% of the IBR plant’s nominal apparent power rating. The target reactive power level
and mode (injection or absorption) shall be specified by the TS operator. The reactive power settings are
allowed to be adjusted locally and/or remotely as specified by the TS operator. The dynamic response of the
IBR plant to any changes in reactive power shall be positively damped with a damping ratio of 0.3 or better.
6. Active-power—frequency response requirements
6.1 Primary frequency response (PFR)
6.1.1 PFR capability
The default reference point of applicability (RPA) for the primary frequency response (PFR) capability
requirements of an IBR plant shall be the point of measurement (POM).
The primary frequency response function and overall response capability of an IBR plant shall meet the
specified performance requirements at the RPA as shown in Figure 9 and Table 6. The IBR plant shall have
the capability to provide primary frequency response in continuous operation region as well as mandatory
operation region as specified in 7.2 and 7.3. 65
The primary frequency response shall include the capability to respond to under-frequency disturbances (by
active power increase) and over-frequency disturbances (by active power decrease). The use of such
capability shall be mutually agreed to between the IBR owner and TS operator.
The primary frequency response controller shall have fixed droop characteristics (kOF and kUF) with default
values as specified in Table 7. It shall be possible to set different levels of droop for under-frequency and
over-frequency conditions. The IBR plant’s frequency droop parameters shall be capable of adjustment at
least to the ranges of available settings specified in Table 7. Frequency droop shall be based on the difference
between IBR continuous rating (ICR) and zero output such that the slopes of the droop curves are always
constant.
IBR plant response during under-frequency (UF) conditions shall be limited by the available active power.
Note that the available active power is limited by IBR continuous rating (ICR) or temporarily IBR short-term
rating (ISR).
65
The operating region where both voltage and frequency are within parameters specified in 7.2 and 7.3. Refer to those sections for
requirements during voltage and frequency ride-through.
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Associated Transmission Electric Power Systems
IBR plant response during over-frequency (OF) conditions shall be limited by the minimum active power
capability (pmin). 66
NOTE 1—Figure 9 shows examples of a frequency-droop characteristic which has different slopes for OF and UF
conditions, illustrating IBR plant response to a similar frequency disturbance, in magnitude, produces a more aggressive
response to UF condition compared to OF condition.
NOTE 2—There may be multiple droop characteristics for under-frequency and over-frequency conditions. While the
specification may not change, different parameters may be specified by the TS operator for different frequency ranges.
Figure 9 —Primary frequency response characteristic
66
For an IBR plant (e.g., energy storage system) pmin may be negative, i.e., charging.
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Associated Transmission Electric Power Systems
Table 6 —Formula for frequency-droop (frequency-power) operation for low-frequency
conditions and high-frequency conditions for IBR plant
 f
− f − dbUF

=
p min pavl , ppre + =
pPFR
min  pavl , ppre + max  0, nom
f nom × kUF


{
Low
frequency
}
 

 
e.g., ICR = 100 MW, kUF = 0.03 Hz/MW (0.05 p.u. droop), dbUF = 0.036 Hz
ppre = 50 MW = 0.50 p.u., pavl = 51 MW = 0.51 p.u., fnom = 60 Hz; f = 59.9 Hz, then
=
p min {0.51,0.50 + ( 60 − 59.9 − 0.036 ) / 60 / 0.05
=
=
= 51 MW
} 0.51 p.u.
} min {0.51,0.5213
 f
− f + dbOF  

=
p max pmin , ppre +=
pPFR
max  pmin , ppre + min  0, nom

f nom × kOF  


{
High
frequency
where
p
pPFR
fnom
f
pavl
ppre
pmin
dbOF
dbUF
kOF
kUF
}
e.g., ICR = 100 MW, kOF = 0.024 Hz/MW (0.04 p.u. droop), dbOF = 0.036 Hz, pmin = 10 MW = 0.10 p.u.
f = 60.1 Hz, ppre = 50 MW = 0.50 p.u., then
0.04} max {0.10, 0.4598
=
p max {0.10, 0.50 + ( 60 − 60.1 + 0.036 ) / 60 /=
=
=
p.u. 45.98 MW
} 0.4598
is the active power output, 67 in p.u. of the IBR continuous rating (ICR) as defined in 3.1
is the active power from PFR in p.u. of the ICR
is the nominal frequency in Hz
is the applicable frequency in Hz
is the available active power as defined in 3.1, in p.u. of the ICR
is the pre-disturbance active power output, defined by the active power output at the point of time the frequency
exceeds the deadband, in the same units as p.
is the minimum active power output due to IBR plant, interconnection agreement or other constraints, in p.u. of the
ICR (see also: definition for pmin in 3.1)
is a single-sided, non-step deadband value for high-frequency in Hz
is a single-sided, non-step deadband value for low-frequency, in Hz
is the constant droop for over-frequency events and is the per unit change in frequency corresponding to 1 per unit
change in power output. Droop can also be expressed in percent change in frequency over 100% change in power.
Droop can also be expressed in Hz/MW, but then must be converted for use in the above equations.
is the constant droop for under-frequency events and is the per unit change in frequency corresponding to 1 per unit
change in power output. Droop can also be expressed in percent change in frequency over 100% change in power.
Droop can also be expressed in Hz/MW, but then must be converted for use in the above equations.
67
Includes positive and negative active power for IBR plant with energy storage systems during low- and high-frequency conditions,
respectively. Use of alternate control means to meet this requirement is permitted.
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Table 7 —Parameters of primary frequency response for IBR plant
Parameter
Units
Ranges of available settings
Minimum
Maximum
Default value
dbUF
Hz
0.06% × fnom
0.025% × fnom
1.6% × fnom
dbOF
Hz
0.06% × fnom
0.025% × fnom
1.6% × fnom
kUF 68
5%
2% 69
5%
kOF
5%
2%
5%
6.1.2 PFR performance
The dynamic performance capability of primary frequency response for IBR plant shall have the following
characteristics:

The overall dynamic response capability of the IBR plant for a step change in applicable frequency
shall be within the ranges specified in Table 8. If the TS operator does not specify parameters for
active power-frequency dynamic response, the default values in Table 8 shall be used. The TS
operator may specify parameters different from default values in Table 8 with due consideration of
system dynamic oscillatory behavior, in which case, parameters shall be as specified by the TS
operator.

The IBR plant shall not be required to change its active power output at a rate greater than its ramping
capability. The maximum available power ramp rate of the IBR plant shall be as fast as technically
feasible. The IBR owner shall inform the TS operator about this limitation.
The closed-loop dynamic response of the active power-frequency controller of the IBR plant, as measured at
the RPA, shall have the capability to meet or exceed the performance specified in Table 8. 70 The steady-state
active power provided in accordance with this clause shall be within the tolerances specified in 4.4.
The response shall be stable and any oscillations shall be positively damped with a damping ratio of 0.3 or
higher. 71 Stable and damped response shall take precedence over rise time and settling time. That is, if it is
shown that for the applicable IBR plant and the given grid to which the IBR plant is connected, stable response
requires a rise time or settling time that is closer to the upper limit defined in Table 8, then this is preferred
to help ensure stable and damped response.
68
Droop has physical units of Hz/MW, however, it is more commonly expressed in per unit. Thus, a 5% droop, or 0.05 p.u. droop,
means a change of 0.05 p.u. in frequency would result in a 1 p.u. change in power.
69
The minimum value of 0.02 p.u. for droop provided here pertains to IBR plant with physically moving mechanical parts, or other
limitations to energy source dynamic response such as fuel cell electrochemical processes. For most other IBR plants, such as batteryenergy storage systems or photovoltaics, where the energy conversion does not involve any mechanical or moving parts, the sudden
amount of change in the power output of the IBR plant may be possible and smaller values of droop are possible to provide larger and
faster frequency response, i.e., fast frequency response (FFR) as specified in 6.2. Of course, much care should be taken to confirm
system stability is maintained and unnecessarily large gains in the control are not used.
70
Refer to Clause 10 and Clause 12 for requirements with regard to model validation and parameterization.
71
Refer to informative Annex L for a discussion of damping ratio.
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Associated Transmission Electric Power Systems
NOTE 1—Dynamic response characteristics are defined on an open-loop basis, which is the effective case when the
inertia of the system is orders of magnitude larger than the IBR rating. 72
NOTE 2—The reaction time starts when the applicable frequency measured at the RPA has deviated outside of the
applicable PFR deadband. Applicable frequency is specified in 4.3.
IBR plant shall be capable of sustaining PFR for as long as the primary energy source is available.
Table 8 —Parameters of active power-frequency response dynamic performance
for IBR plant
Parameter
Units
Default value
Reaction time
Seconds
0.50
Rise time
Seconds
4.0
Settling time
Seconds
10.0
Unitless
% of change
0.3
Max (2.5% of change or 0.5% of ICR)
Damping ratio
Settling band
Ranges of available settings
Minimum
Maximum
0.20
1
(0.5 for WTG)
2.0
20
(4.0 for WTG)
10
30
0.2
1
1.0
5
6.1.3 PFR utilization in operations
During temporary frequency disturbances, for which the applicable frequency is outside the required
deadband dbOF and dbUF as specified in Table 7 but still within the continuous operation region or mandatory
operation region, the IBR plant shall adjust its active power output from the pre-disturbance levels, according
to the formulas in Table 6. The active power output shall be as defined by the relevant formula in Table 6.
Response to under-frequency disturbances shall not be required for IBR plant operating at available active
power (Pavl). Should the IBR plant be operating at less than Pavl while having the capability to operate at
available active power (i.e., curtailed operation), response to under-frequency disturbances shall be required,
except for limitations specified by the TS operator.
Where the operation of the IBR plant with a headroom (i.e., curtailed operation) is required by the TS operator
to address under-frequency disturbances, the IBR plant shall have the capability to dynamically maintain this
headroom as the prime energy source is varying.
Response to over-frequency disturbances shall not be required for IBR plant operating at minimum active
power capability (Pmin). Should the IBR plant be operating at greater than Pmin, response to over-frequency
disturbances shall be required.
Hybrid IBRs with storage that are capable of absorbing power when providing PFR, may limit PFR provision
to active power ≥ 0 if agreed to by the TS operator/TS owner. 73
Total active power output may be capable and allowed to temporarily exceed the IBR continuous rating (ICR)
of the IBR plant up to its IBR short-term rating (ISR) at the RPA. 74
The PFR magnitude inherently becomes zero when the frequency returns within the applicable deadbands
because the PFR has proportional response. At that point, IBR plant shall return to its normal operation.
72
In small isolated TSs, such as island systems or where a portion of a larger interconnection becomes islanded, the dynamic response
varies with the TS inertia. When connected to a large continental interconnection, closed loop and open-loop response are practically
identical.
73
This is to address potential concerns about tax credits in some jurisdiction that require restrict charging from renewable co-located
resources only.
74
Primary frequency response is activated occasionally but typically does not lasts for a duration anywhere close to the validity of the
IBR short-term rating (ISR), because PFR begins to be replaced by secondary frequency response in typically less than 1 min.
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In case of energy storage systems, the dynamic performance during PFR provision when crossing over from
exporting to importing active power (and vice versa) shall not prevent the IBR plant from meeting the
requirements of Table 8.
6.2 Fast frequency response (FFR)
6.2.1 FFR capability
The default reference point of applicability (RPA) for the fast frequency response (FFR) capability
requirements of an IBR plant shall be the point of measurement (POM). Where the FFR is activated under
direct control from the IBR unit, the RPA may be the POC.
The IBR plant shall have fast frequency response (FFR) capability for under-frequency conditions, with
exceptions specified by the TS operator in coordination with the load balancing entity. 75, 76 FFR capability
may be utilized for the purpose of ancillary service agreement offerings within certain load balancing entities
or power markets.
NOTE 1—Fast frequency response (FFR) is defined in 3.1 as “active power injected to the grid in response to changes
in measured or observed frequency during the arresting period of a frequency excursion event to improve the frequency
nadir or initial rate-of-change of frequency.” FFR capability is a faster response capability to frequency events as opposed
to the more traditional and slower PFR response capability specified in 6.1 This is illustrated in Figure 10 below adopted
from the NERC white paper, Fast Frequency Response Concepts and Bulk Power System Reliability Needs [B73].
NOTE 2—For example, in case of a battery energy storage system, if it is capable to provide a sustained and full response
to a frequency deviation beyond a dead band as specified by the TS operator, as directed by the load balancing entity, in
less than 1 s, then such a response may be defined as FFR. The FFR parameters may be tuned to have droop of 1% (i.e.,
can provide 100% change in power for 1% change in frequency).
NOTE 3—Wind turbine generators (WTGs) can temporarily extract energy from the mechanical mass of the rotating
shaft of the turbine and inject this into the grid quickly, for under-frequency events only, to provide FFR. See 6.2.3 for
specific requirements for FFR from WTGs.
The TS operator and the load balancing entity in coordination with IBR owner may specify different FFR capability for an IBR plant
considering mechanical or chemical performance constraints in the IBR plant’s energy resource response and other technical limitations
as specified by the IBR owner.
76
The IBR plant may also have FFR capability for over-frequency conditions as specified by the TS operator and the load balancing
entity, and mutually agreed to by the IBR owner.
75
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Associated Transmission Electric Power Systems
This figure is printed with permission from The Regents of the University of California through Lawrence
Berkeley National Laboratory, © 2020.
Figure 10 —BPS frequency control time frames
63
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
6.2.2 FFR performance
An IBR plant shall meet the FFR performance requirements as specified in 6.2.2.1. Utilization of FFR
capability of IBR plant shall not be enabled by default.
See 6.2.3 for specific capability and performance requirements for FFR from WTG. IBR with WTG that are
interconnected to an ac transmission system via a dedicated VSC-HVDC transmission facility shall be
allowed to meet the FFR performance requirements as specified in either 6.2.2.1 or 6.2.3.
The FFR step response time capability, defined as the time from the triggering event to the time when the
change in active power due to FFR reaches 90% of its target value, shall be adjustable to no greater than 1 s,
including the reaction time for triggering FFR. 77 The response shall be stable and any oscillations shall be
positively damped with a damping ratio of 0.3 or better. 78, 79 Stable and damped response shall take
precedence over response time. That is, if it is shown that for the applicable IBR plant and the given TS to
which the IBR plant is connected, stable response requires a response time greater than 1 s, and this is agreed
to between the IBR owner and the TS operator, then this is acceptable and may still constitute FFR.
Further, the following requirements shall apply:

FFR capability shall be an autonomous function that is automatically self-deployed by the IBR plant
and shall provide a fast and short-term temporary active power response to frequency deviations.

Triggers for FFR may be specified based on frequency deviation.

IBR plant shall be capable of sustaining FFR for as long as the IBR plant energy resource is available
or until supplanted by primary, secondary, or tertiary frequency response, whichever is less.

Active power response during FFR actuation may temporarily exceed the IBR continuous rating
(ICR) but shall not exceed the IBR short-term rating (ISR). See definitions of ICR and ISR in 3.1.

FFR and PFR shall actuate independently from each other and shall complement each other in power
output as follows:
{
=
p min pavl , ppre + pPFR + pFFR1 + pFFR2 + pFFR3 + pFFR4
}
 Note that FFR1 is described in 6.2.2.1. FFR2 through FFR4 equations can be found in Annex K.
In the future, there may be other possible forms of FFR that are not included here.
NOTE—Given that FFR is an evolving functional and performance capability, this clause specifies only FFR1 capability
as mandatory 80 (see 6.2.2.1), and provides a complementary framework with selected technical minimum capability and
performance requirements for other variants of FFR a TS operator may require. A TS operator may use these framework
requirements as a starting point for specifying more detailed capability and performance requirements for other evolving
FFR variants, and consider Annex K, which includes emerging examples of FFR specifications and applicable leading
international practices.
6.2.2.1 FFR1: FFR proportional to frequency deviation
The fast frequency response function and overall response capability of an IBR plant shall meet a FFR
performance proportional to frequency deviation (so-called FFR1 performance) at the RPA as shown in
77
Note that there are limitations on the response times that can be provided by WTGs due to the inertia-based response of the WTG
system. See NOTE 3 of subclause 6.2.1 for description, and 6.2.3 for specification of WTG-based energy extraction.
78
The damping ratio of the response of the active power of the IBR plant may be calculated using the same approach shown in Annex L,
but applied to active power as the measured signal.
79
Refer to informative Annex L for a discussion of damping ratio.
80
FFR1 performance specifications are similar to the PFR requirements specified in 6.1 with the difference that FFR1 parameters specify
a faster and more aggressive performance.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Table 9 and Table 10. The FFR1 parameters shall be adjustable within the ranges of available settings
specified in Table 10.
NOTE 4—An FFR1 response is proportional to frequency deviation and, hence, is mathematically similar to PFR, with
the main difference being a faster response time and the parameters.
NOTE 5—FFR1 is not applicable for WTG. See 6.2.3.
The IBR plant shall have the capability of operation with the required fast frequency response in the normal
operating region where both voltage and frequency are within parameters specified in 7.2 and 7.3. 81
Response to under-frequency disturbances shall not be required for IBR plant operating at available active
power (Pavl). Should the IBR be operating at less than Pavl while having the capability to operate at available
active power (i.e., curtailed operation), response to under-frequency disturbances shall be required.
Table 9 —Formula for FFR1 (proportional to frequency deviation)


f UF,FFR1 − f  
=
pFFR1 min  pavl , ppre + max  0,

 f nom × k UF,FFR1  

 

Low
frequency
e.g., ICR = 100 MW, kUF,FFR1 = 0.006 Hz/MW (0.01 p.u. or 1% droop), fUF,FFR1 = 59.6 Hz
ppre = 50MW = 0.50 p.u., pavl = 100 MW = 1.0 p.u., fnom = 60 Hz; f = 59.5 Hz, then
pFFR1 = min{1.00, 0.50 + max{0, (59.6 – 59.5)/60/0.01}} = min{1.00,0.667} = 0.667 p.u. = 66.7 MW
where
pFFR1
is the active power from FRR1 in p.u. of the IBR continuous rating (ICR) as defined in 3.1
f
is the applicable frequency in Hz
fUF,FFR1
is the underfrequency trigger for FFR1 in Hz
kUF,FFR1
is the constant droop for underfrequency events and is the per unit change in frequency corresponding
to 1 per unit change in power output. Droop can also be expressed in Hz/MW, but then must be
converted for use in the above equation.
The operating region where both voltage and frequency are within parameters specified in 7.2 and 7.3. Refer to those sections for
requirements during voltage and frequency ride-through.
81
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Table 10 —Parameters of FFR1
Parameter
Units
Ranges of available settings
Default value
Minimum
Maximum
fUF,FFR1
Hz
99.94% of fnom
99.17% of fnom
99.94% of fnom
kUF,FFR1
%
1%
1% 82
5%
6.2.2.2 Other variants of FFR
As applicable, the TS operator, in coordination with the load balancing entity, may specify other variants of
FFR capability and performance requirements at the RPA of an IBR plant considering the following
performance criteria:

Triggers for FFR other than those based on frequency deviation may be specified based on ROCOF,
or a combination of frequency deviation and ROCOF using the applicable parameters as elaborated
in Annex K.

Dynamic performance may be specified using the applicable parameters such as reaction and
response time (see Annex K for examples).

The tuning of dynamic performance parameters of FFR shall be carefully studied on a case-by-case
basis to help ensure it does not inadvertently result in oscillatory behavior for a given system or
unnecessary curtailment of an IBR plant. Particular attention should be given to the potential for
adverse interaction with the torsional oscillation modes of synchronous turbine-generators connected
to the TS.

For an IBR plant that uses energy stored in an IBR’s energy resource, 83 performance criteria shall be
specified for any active power withdrawal from the TS by the IBR plant to restore its ability to provide
a future FFR response.
Annex K provides more details on potential future consideration related to so-called FFR, including some
emerging examples of FFR variants that may be plausible in the future.
NOTE—Requirements for utilization and provision of FFR as a service (e.g., including reserving head room) are outside
the scope of this standard.
6.2.3 Fast frequency response from wind turbine generator (WTG)–based IBR plant
The fast frequency response from wind turbine generator (WTG)–based IBR plant at their POM takes the
form of a temporary increase of active power output to limit the frequency drop after a major loss of
generation on the interconnected grid. This WTG-based IBR plant FFR capability shall be used to handle
significant frequency deviation while WTG continues to remain in service. For underfrequency disturbance,
the FFR from WTG-based IBR plant shall comply with requirements specified below:

WTG-based IBR plant shall provide an adjustable frequency threshold dead band within a range of
available settings from −0.1 Hz to 1.0 Hz with respect to nominal frequency (60 Hz or 50 Hz).

The temporary increase of IBR plant active power output shall be equal to at least 5% of the total
rated power of the WTGs that are in service and operating at or above 25% of rated power. For
example, if there are 30 WTGs in a plant, each rated 4 MW and 25 are producing 1 MW or more,
Care is taken to confirm system stability is maintained and unnecessarily large gains in the control are not used.
Examples include electrical energy stored in a dc capacitor, kinetic energy stored in the rotation of a wind turbine rotor or a flywheel,
and chemical energy stored in battery energy storage.
82
83
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Associated Transmission Electric Power Systems
then the temporary increase of IBR plant active power output shall be at least 5 MW (0.05 × 4 × 25
= 5). 84
84

Once activated at a given frequency threshold, WTG-based IBR plant shall provide temporary
increase of active power output at the RPA by a fixed minimum amount (~5%) provided active power
(wind) is available.

WTG-based IBR plant shall provide a temporary increase of active power output for the duration
from 5 s to 10 s (from the start of active power ramp up to the start of active power ramp down).

WTG-based IBR plant shall limit time to reach maximum temporary increase of active power output
to 1.5 s or less.

WTG-based IBR plant shall limit decrease in active power output during energy recovery to 20% or
less of pre-disturbance active power output. The duration of the energy recovery period should be
maximized to reduce the magnitude of the initial decrease of active power.

WTG-based IBR plant shall be capable of operating repeatedly in FFR mode with a 2-min delay after
the end of the energy recovery period following the previous operation.

For underfrequency disturbance, if FFR is activated, FFR shall take precedence over PFR. PFR shall
be activated at the end of energy recovery period following FFR support, subject to availability of
active power.
Note that since this capability is tied with individual WTG unit, which in some cases may not result in the desired overall plant output.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
7. Response to TS abnormal conditions
7.1 Introduction
Abnormal conditions, as defined in 7.2 and 7.3 for voltage and frequency respectively, can arise on the TS
to which the IBR plant shall appropriately respond. This response contributes to the stability of the TS, as
well as the avoidance of damage to connected equipment, including the IBR plant. All performance
requirements specified in these subclauses shall be met at the reference point of applicability specified in 4.2
and shall refer to the applicable voltages specified in 4.3, unless otherwise stated.
7.2 Voltage
7.2.1 Voltage protection requirements
Requirements as specified in 9.3 shall apply.
7.2.2 Voltage disturbance ride-through requirements
7.2.2.1 General requirements and exceptions
The performance required of an IBR plant during voltage disturbances is specified in this clause. The default
reference point of applicability (RPA) for the voltage disturbance ride-through requirements of an IBR plant
shall be the point of measurement (POM). Specific requirements apply to IBR units at their POCs.
The voltage disturbance ride-through requirements specified in this clause do not apply when applicable
frequency is outside of the continuous operation region and the frequency ride-through mandatory operation
region specified in 7.3.2. 85
The IBR plant shall be designed to provide the voltage disturbance ride-through capability specified in this
clause. Any tripping of the IBR plant, or other failure to provide the specified ride-through capability, due to
IBR plant self-protection as a direct or indirect result of a voltage disturbance within a ride-through region,
shall constitute non-compliance with this standard.
Exception: For a voltage disturbance that reduces the applicable voltage at the RPA to less than 50% of
nominal, the IBR plant shall be considered compliant with this standard if the post-disturbance apparent
current of the IBR plant is not less than 90% of the pre-disturbance apparent current. 86
Exception: The IBR plant shall satisfy requirements of this clause unless tripping of the IBR plant is required
to clear faults either internal to the IBR plant, on the interconnection system (IBR tie line) or any portion of
the TS which may provide sole connectivity between the IBR plant and the TS.
The applicable voltage for both temporary low voltage (including balanced and unbalanced faults on the TS)
and high-voltage disturbances is defined in 4.3.
Frequency variation may occur during voltage disturbances and vice-versa.
An IBR plant typically consists of tens to hundreds of individual IBR units. The requirements here apply to the IBR plant at the RPA.
There is no single way, whether by testing or simulation, to ensure with absolute certainty that every single IBR unit in the facility rides
through all possible disturbances. Furthermore, at any given time when a disturbance occurs, since most IBR technologies are renewable
facilities with intermittent resources (wind and sunlight), there will be a different number of IBR units that are on-line at the moment
prior to the disturbance. Thus, ride-through response cannot be a purely deterministic requirement. For example, for a given event, if
one out of one hundred IBR units in an IBR plant trips, it cannot be considered as a failure of ride-through. For these reasons, the 10%
reduction in apparent current is allowed to cater for such potential stochastic behavior. The IBR owner and the TS owner may, through
mutual agreement, agree to a different percentage reduction allowance.
85
86
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Associated Transmission Electric Power Systems
The nominal voltage is used as a base value to calculate per unit values for the continuous operation region
as well as per unit values specified in Table 11 and Table 12.
Except for 500 kV system nominal voltage, the continuous operation region is when the applicable voltage
is ≥ 0.9 per unit and ≤ 1.05 per unit. For 500 kV system nominal voltage, the continuous operation region is
when the applicable voltage is ≥ 0.9 per unit and ≤ 1.10 per unit. 87 The nominal transmission system voltage
may be different from standard nominal system voltages specified in ANSI C84.1. The TS owner shall specify
the nominal voltage to be used as a base value to calculate per unit values in Table 11 and Table 12, as well
as the continuous operation region. For example, the TS owner may specify a nominal voltage of 525 kV
with a continuous operation region when applicable voltage is ≥ 0.9 per unit and ≤ 1.05 per unit at 525 kV
voltage base.
The IBR plant shall ride through a voltage disturbance event wherein the applicable voltage exceeds or is
less than the voltage range representing the continuous operation region, except for voltage magnitude
deviations more severe than the voltage thresholds and persisting for greater than the associated durations as
specified in either Table 11 and Table 12. The applicability of Table 11 and Table 12 for this requirement
shall be determined during the IBR plant design evaluation as specified in Clause 12. The specified duration
in Table 11 and Table 12 is cumulative over one or multiple disturbances within a 10-s time period (window)
except when applicable voltage is greater than 1.05 per unit and less than or equal to 1.10 per unit, in which
case the specified duration is cumulative over one or multiple disturbances within a 3600-s time period
(window). These requirements are subject to consecutive voltage deviation ride-through capability
requirements specified in 7.2.2.4. The TS owner may specify different voltage magnitudes and respective
ride-through durations. 88
Upon the applicable voltage returning to the continuous operation region, the IBR plant shall be able to
restore output as specified in 7.2.2.6.
At transmission voltages other than 500 kV nominal, ANSI C84.1 specifies maximum voltages that are approximately 105% of the
nominal values. For 500 kV nominal, ANSI C84.1 specifies a maximum voltage of 550 kV, which is 1.10 per unit of nominal.
The applicable voltage as defined in 4.3 includes phase-to-ground voltage for TS designed for effective grounding. This implies that
the IBR plant shall ride through a close-in fault regardless of type for a specified time duration. For example, an IBR plant consisting of
WTGs is required to ride through a close-in three-phase fault as well as a close-in phase-to-ground fault for 0.16 s. The TS owner may
require longer ride-through time for less severe faults, i.e., phase-to-ground faults.
87
88
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Associated Transmission Electric Power Systems
Table 11 —Voltage ride-through requirements at the RPA for IBR plants with
auxiliary equipment that cause ride-through limitations 89
Applicable voltage
(p.u.) at the RPA
V > 1.20
V > 1.10
V > 1.05
V < 0.90
V < 0.70
V < 0.50
V < 0.25
V < 0.10
Operating mode/response
May ride-through or may trip
Mandatory operation
Continuous operation 90
Mandatory operation
Mandatory operation
Mandatory operation
Mandatory operation
Permissive operation 91
Minimum ride-through time (s)
(design criteria)
NA
1.0
1800
3.00
2.50
1.20
0.16
0.16
Table 12 —Voltage ride-through requirements at the RPA for IBR plants without
auxiliary equipment that cause ride-through limitations
Applicable voltage
(p.u.) at the RPA
V > 1.20
V > 1.10
V > 1.05
V < 0.90
V < 0.70
V < 0.50
V < 0.25
V < 0.10
Operating mode/response
May ride-through or may trip
Mandatory operation
Continuous operation90
Mandatory operation
Mandatory operation
Mandatory operation
Mandatory operation
Permissive operation91
Minimum ride-through time (s)
(design criteria)
NA
1.0
1800
6.00
3.00
1.20
0.32
0.32
NOTE 1—For interconnection at 500 kV system nominal voltage, the minimum ride-through time is infinite when
applicable voltage is > 1.05 per unit and ≤ 1.10 per unit at 500 kV base.
NOTE 2—For isolated IBR, regardless of their energy resource, interconnecting via a dedicated VSC-HVDC
transmission facility, the voltage ride-through requirements specified in Table 12 applies.
NOTE 3—For IBR plants consisting of photovoltaic (PV) and ESS that do not use auxiliary equipment that causes ridethrough limitations, as determined during the IBR plant design evaluation in Clause 12, the voltage ride-through
requirements specified in Table 12 applies.
NOTE 4—The nominal system voltage as defined in ANSI C84.1 is used as a base to derive per unit values in Table 11
and Table 12. The respective maximum voltage in ANSI C84.1 is adopted as a high-voltage limit for the continuous
operation region. When the TS is normally operated outside of continuous operation region, the TS owner should provide
a base voltage value and respective continuous operation range for purposes of voltage ride-through requirements.
NOTE 5—In case of hybrid IBR plants consisting of various IBR technologies, some combination of voltage ride-through
capability requirements specified in Table 11 and Table 12 may need to be applied. In such a circumstance, the capability
shall be based mutual agreement between TS owner and IBR owner.
A typical large turbine could have 100 kW to 200 kW of auxiliary equipment—most of which are motors which run pumps or fans.
Large offshore turbines could have more than 400 kW of auxiliaries. Due to the large power load, these auxiliaries are typically fed by
the ac terminals of the turbine-driven generator. Since there are a lot of motors in the kW range, these are sourced from suppliers’
standard offerings. It is not easy to find motors and pumps capable of long-term LVRT as standard offerings in the kW range. Special
designs for kW range motors, pumps, and fans in low volumes may not be cost effective. There are also safety standards (NEC, etc.)
that have protection requirements that may be difficult to meet when required to operate for long time at lower voltages. Fuel cells have
motors, pumps, etc. with similar limitations.
90
Refer to definitions of continuous operation and mandatory operation. The intent is to distinguish between IBR plant’s response during
different modes of operation. Thus, the terms continuous operation and mandatory operation are related to the operating mode, and are
distinct from the allowable minimum ride-through times for which the IBR plant is required to withstand the specified voltage ranges.
91
While it seems intuitive to require an IBR plant to continue to exchange current when the applicable voltage at the RPA is below 10%
from a system protection perspective (since current injection at low voltage may aid protection schemes in detecting and clearing faults),
it is necessary to understand risks and benefits to help ensure that the ultimate objective, which is successful ride-through of the IBR
plant, is not jeopardized. If required to inject current for low voltages at the RPA, the IBR plant may ultimately trip due to consequences
arising from loss of synchronism, temporary overvoltage upon fault clearance and challenges in controlling dc-side voltage of the
converter. Mutual consultation, and where appropriate studies, among all stakeholders is encouraged to understand the implications of
the permissive operation on system performance.
89
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Associated Transmission Electric Power Systems
For voltage disturbances where the applicable voltage is outside the ride-through operating region parameters
(voltage magnitudes and corresponding minimum durations, including any cumulative duration within a 10-s
period consistent with 7.2.2.4), requirements for voltage ride-through mode or restore output subsequent to
the voltage disturbance shall not apply though the IBR plant may ride-through and may restore output
accordingly. This standard does not specify any mandatory voltage protection requirements. Refer to 7.2.1
and 9.3 for further details.
The voltage ride-through requirements of this clause are illustrated in the informative Figure D.5 through
Figure D.8.
7.2.2.2 Voltage disturbances within continuous operation region
Voltage disturbances of any duration, for which the applicable voltage as specified in 4.3 remains within the
continuous operation region, shall not cause the IBR plant to trip from the TS. The IBR plant shall remain in
operation during any such disturbance, and shall continue to deliver pre-disturbance level of active power or
available active power, whichever is less. Changes of active power are permitted in response to control
commands in accordance with 4.6 or in response to other control settings. Temporary deviations of active
power output are permitted as agreed upon between the IBR owner and the TS operator.
If the IBR plant cannot deliver both active and reactive power due to its current limit (or apparent power
limit), when the applicable voltage is below 95%, then preference shall be given to active or reactive power
according to requirements specified by the TS operator.
Exception: If required for self-protection, the IBR plant may trip if the negative sequence component of the
applicable voltages is greater than 3% of the nominal voltage for greater than 10 s, OR greater than 2% of
the nominal voltage for 300 s, provided that the voltage unbalance is neither caused nor aggravated by
unbalanced currents of the IBR plant. The IBR plant may also trip for negative sequence component of the
applicable voltage exceeding 6.7% 92 of the nominal voltage for a duration determined by the TS owner based
on feasible shunt or series fault scenarios, 93 provided that the voltage unbalance is neither caused nor
aggravated by unbalanced currents of the IBR plant. Additionally, when the duration of the negative sequence
component of the applicable voltage is greater than the specified time limit, the IBR plant shall remain in
operation for as long as possible, and tripping shall be the last resort.
7.2.2.3 Low- and high-voltage ride-through within the mandatory operation region
7.2.2.3.1 General
Refer to 4.3 for applicable voltages for low- and high-voltage ride-through capability.
7.2.2.3.2 Low- and high-voltage ride-through capability
When the IBR unit enters a ride-through mode, the response of the IBR plant is dominated by the response
of IBR units and any supplemental IBR devices. The ride-through mode is also widely referred to as fault
ride-through mode. The IBR unit shall have capability to select operation in either active current priority
mode or reactive current priority mode during a high- or low-voltage ride-through events. By default, the
IBR unit shall operate in reactive current priority mode during high- and low-voltage ride-through events. If
Per engineering judgement, maximum possible negative sequence voltage within the continuous operation region.
If TS owner expects that the negative sequence component of the applicable voltage could be > 6.7% of the nominal voltage within
the continuous operation region, then TS owner should consult with the IBR owner for the ride-through capability. At the time of writing
of this standard, neither test data nor technical literature is available to aid with development of minimum ride-through time for this
condition.
92
93
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Associated Transmission Electric Power Systems
requested by the TS owner, and mutually agreed with the IBR owner, the IBR unit may operate in active
current priority mode 94 for both the high and low-voltage ride-through events.
The IBR unit shall be capable to separately set the required level of reactive current injection or dynamically
provide reactive current for a voltage deviation during low, and during high-voltage ride-through modes of
operation. For example, for a given voltage deviation, the TS owner may prefer a large amount of reactive
current injection at cost of active current 95 during low-voltage ride-through operation. However, for the same
voltage deviation during high-voltage ride-through operation, the TS owner may prefer no or limited
reduction in active current. 96
IBR units shall be capable of meeting the performance specifications defined in Table 13. Detailed studies
(either during the interconnection process or periodic planning assessments by the TS owner) may identify a
need for modifications to these performance specifications.
The plant controller shall not prohibit or prevent controls of IBR units and any supplemental IBR devices to
meet ride-through performance requirements.
7.2.2.3.3 Low and high-voltage ride-through performance
During low-voltage disturbances, including faults on the TS, for which the applicable voltage with the lowest
magnitude is within the mandatory operation region or during high-voltage disturbances for which the
applicable voltage with the greatest magnitude is within the mandatory operation region, the IBR plant shall
continue to exchange current with the TS based on requirements defined in 7.2.2.3.4. During a ride-through
mode, the IBR unit shall be capable to inject current to its maximum limit (i.e., maximum current). 97 The TS
owner may specify required magnitude of current injection within the IBR unit’s limits based on system
studies.
During low-voltage disturbances, including faults on the TS, for which the applicable voltage with the lowest
voltage magnitude is within the permissive operation region, the IBR plant:

Shall not trip.

May continue to exchange current with the TS based on requirements specified in 7.2.2.3.4 or may
operate in current blocking mode. Active and reactive current oscillations that are positively damped
are permitted during the disturbance and post-disturbance period.

If operates in current blocking mode, shall restart current exchange in less than or equal to five cycles
of applicable voltage returning to continous operation region or mandatory operation region. The
restart of current exchange is performed by IBR units, when applicable voltage at the RPA (as
94
Active current priority mode may provide some reliability benefits for bulk power systems with certain characteristics, e.g., low system
inertia, and is required in a few countries around the world. On the other hand, active current injection for close-in faults may cause IBR
plant instability, and active current priority may negatively affect the IBR plant’s ride-through capability subject to the capability of the
equipment between IBR units and the fault, and beyond, to absorb the active power injected by the IBR plant, hence warranting the
mutual agreement with the IBR owner. Refer to Boemer [B6], EirGrid Grid Code [B16], EirGrid All Island TSO [B17], Erlich et al.
[B20], and Weise [B113] for further reading.
95
While it may be intuitive to require large reactive current during low-voltage ride-through, the trade-off between maximizing active
and reactive currents for shallow disturbances or faults is not so straightforward for wind turbines. If little or no active current is delivered
by the wind turbine during faults, the rotor loses counter-torque. For longer shallower faults this results in the rotor running into its
overspeed limits, and if nothing is done the blades may shear off. When the wind turbine rotor gets close to its overspeed limits the wind
turbine blades are “pitched out” thus reducing the efficiency of energy capture from the wind to compensate for the reduction in countertorque. After the fault is eventually cleared, the blades remain in this inefficient position for several seconds until pitch motor travel is
able to bring the blades back to their optimal position. During this time, the wind turbine produces only a fraction of the active power it
was producing prior to the fault. If post-fault frequency recovery is a concern, then it may be necessary to sustain some active current
during the fault even if it is at the expense of some reactive current. For deeper faults (say below 50% voltage), it is an easier trade-off
to improve reactive current as the fault durations are very low and the rotor inertia reduces the likelihood of overspeed.
96
This could be achieved by appropriately setting reactive current gain for high-voltage ride-through.
97
Whenever the IBR unit is operating without primary energy source, ability to inject current during ride-through may be limited.
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Associated Transmission Electric Power Systems
interpreted at the IBR unit terminals) returns to continous operation region or mandatory operation
region.
7.2.2.3.4 Current injection during ride-through mode
The default reference point of applicability (RPA) for the current injection during ride-through mode of an
IBR unit shall be the point of connection (POC) of the IBR unit.
The type and magnitude of current injection during a ride-through mode of operation (mandatory operation
and permissive operation as applicable) shall be dependent 98 on voltage deviation from the IBR unit terminal
(POC) 99 nominal voltage when the applicable voltage at the RPA (as interpreted at the IBR unit terminals) is
outside of the continuous operation region. The IBR unit shall maintain automatic voltage control during a
ride-through mode. 100 If requested by the TS operator, automatic voltage control may be disabled.
During a ride-through mode including fault conditions, injection of current from IBR units shall have a
fundamental frequency component 101 same as fundamental frequency of the terminal voltage with the
following exceptions:
a)
During a fault and a period immediately following a fault clearing, off-nominal frequency
components including abnormal harmonic components, shall be permitted due to the transients,
transformer inrush, etc.
b)
In case of type III WTG, when the rotor is crowbarred or for close-in faults where control of the rotor
current is lost. 102
c)
Small deviations in frequency of output current are permissible when severe or close-in three-phase
faults cause phase-locked loop (PLL) to not track IBR unit terminal voltage frequency. 103
The following specifies characteristics of injected current by IBR units when operating in a reactive current
priority mode or active current priority mode.
The ability to inject reactive current may be limited and dependent on the pre-disturbance operating condition
when the IBR unit is specified to operate in active current priority mode by TS owner. After prioritizing
available active current (up to IBR unit’s maximum current rating), the IBR unit’s remaining capability shall
be used to inject reactive current per characteristics specified below. In case of ESS, when operating in active
current priority mode, IBR unit shall prioritize active current to maintain pre-disturbance charging or
discharging rate.
For balanced faults, an IBR unit shall inject reactive current dependent on IBR unit terminal (POC) voltage.
The difference between reactive current injection during a fault and a pre-fault reactive current output is an
incremental positive-sequence reactive current (∆IR-1). The incremental positive-sequence reactive current
shall not be negative. 104 During a fault condition, i.e., operating in a low-voltage ride-through mode, priority
The use of the word dependent intentionally does not specify a proportional or linear relationship.
Often referred as the “inverter terminal.”
100
The K-factor–based proportional control is considered closed loop automatic control.
101
This requirement is not about frequency measurement but about IBR units’ ability to track system frequency during a fault condition.
102
If the rotor is crowbarred then fault current flowing from the stator may contain off-nominal frequency components. Additionally,
for severe or close-in unbalanced faults, if control of the rotor-side converter is lost then fault current flowing from the stator may contain
off-nominal frequency components. Crowbar is used for self-protection as a last resort.
103
For severe or close-in three-phase faults, the phase-locked loop (PLL) may not be able to track the IBR unit terminal voltage
frequency. During this time, the applicable frequency and phase angle may shift, but is expected to be small. In this situation, IBR unit
may only be able to inject current at pre-fault frequency.
104
Before fault, if IBR unit is injecting 50 A of reactive current and during a fault it injects 200 A of reactive current then the resulting
reactive current is 150 A higher than the pre-fault reactive current. However, if before fault, IBR unit is absorbing 50 A of reactive
current and during a fault it injects 200 A of reactive current then the resulting reactive current is 250 A higher than the pre-fault reactive
current. The opposite is expected when IBR unit is operating in high-voltage ride-through mode.
98
99
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shall be given to reactive current injection with any residual capacity being supplied as active current unless
the IBR unit is specified to operate in active current priority mode by the TS owner. 105
For unbalanced faults, in addition to increased positive-sequence reactive current, the IBR unit shall inject
negative sequence current:

Dependent on IBR unit terminal (POC) negative sequence voltage and

That leads the IBR unit terminal (POC) negative sequence voltage by an allowable range as specified
below:

90 degrees to 100 degrees 106 for full converter-based IBR units

90 degrees to 150 degrees for type III WTGs 107
Assuming pre-fault negative sequence current output is zero or negligible, the negative sequence reactive
current injection during a fault is an incremental negative sequence reactive current (∆IR-2). If the IBR unit’s
total current limit is reached, either ∆IR-1, or ∆IR-2, or both may be reduced with a preference of equal
reduction in both currents. Additionally, the incremental positive-sequence reactive current (∆IR-1) injection
shall not be reduced below incremental negative sequence reactive current (∆IR-2). In case of type III WTGs,
the ∆IR-1 and ∆IR-2 injection during a fault is driven by machine parameters and control dynamics and may
not be controllable in a manner described above.
Regardless of fault type, the IBR unit shall meet performance requirements specified in 7.2.2.3.5.
This standard intentionally does not specify magnitude of incremental positive and negative sequence
reactive current injection during a fault condition. It is impractical to specify a value or range of values that
meets the needs for all IBR plant interconnections. The TS owner should consider specifying required
magnitude of incremental positive and negative sequence reactive currents during faults per respective system
needs. The commonly used approach is to specify a relationship between voltage change at IBR unit terminals
(POC) and required incremental reactive current. 108 At minimum, the IBR unit shall be capable of following:

Depending on mode of operation (active or reactive current priority), the IBR unit shall be capable
of prioritizing active or reactive current equal to its maximum current rating when the IBR unit
terminal voltage is less than or equal to 50% of nominal voltage. Prioritizing active or reactive current
up to the IBR unit’s maximum current rating for less severe voltage deviation is permitted.

When operating in reactive current priority mode, the IBR unit shall be capable of absorbing reactive
current of 30% of its maximum current rating when the IBR unit terminal voltage is greater than or
equal to 115% of nominal voltage. Absorbing reactive current up to the IBR unit’s maximum current
rating for less severe voltage deviation is permitted.

When operating in reactive current priority mode, a full converter-based IBR unit shall be capable of
injecting negative-sequence reactive current of 50% of its maximum current rating when the IBR unit
terminal negative-sequence voltage is greater than or equal to 25% of nominal voltage. Injecting
higher negative-sequence reactive current for a lower negative-sequence voltage at IBR unit terminals
Within the total current limits of the IBR unit, the magnitude and mix of active and reactive currents during the fault may be negotiated
between the IBR owner and TS owner. Reactive current is desired to support voltage and to activate protective devices. Active current
may be desired to support frequency during the fault. For wind turbines, active current provides some counter-torque during the fault.
This counter-torque reduces the likelihood of rotor overspeed which may be have to be controlled by pitching the blades. Pitching the
blades during the fault results in decreased efficiency of energy extraction from the wind leading to reduced power output immediately
after the fault.
106
In the case of a synchronous machine, the negative sequence resistance is typically a fraction of the negative sequence reactance. As
such, the negative sequence current is mostly reactive and leads the terminal voltage (generator convention for current polarity).
107
Refer to Annex J for more details. The TS owner may specify a more precise control of angle between negative sequence voltage and
current.
108
For example, K-factor as specified in the German VDE-AR-N 4120 [B110] and VDE-AR-N 4130 [B111].
105
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is permitted. In case of type III WTGs, the negative-sequence current injection is due to machine
parameters and control dynamics. Please refer to Annex J for more details.
In the case of isolated IBR(s) interconnected via a dedicated VSC-HVDC transmission facility, the
requirements specified in this clause apply to the point of connection (POC) at the dc-ac converting station
as illustrated in Figure 2.
In the case of an energy storage system, both as standalone or a hybrid IBR plant (regardless of ac or dc
coupling), and regardless of mode of operation (charging, discharging, or idling), requirements specified in
this clause apply at the respective POCs.
7.2.2.3.5 Performance specifications
For a large disturbance or a step change in voltage, measured at IBR unit terminals (POC), where voltage
goes outside of the continuous operation region (as interpreted at IBR unit terminals), the IBR unit current
response shall meet the performance specifications specified in this clause. These specifications also apply
to fault events (both balanced and unbalanced) on the TS. The IBR unit shall have the capability as specified
in Table 13.
Table 13 —Voltage ride-through performance requirements
Parameter
Type III WTGs
All other IBR units
Step response timeb, c, d
NAa
≤ 2.5 cycles
Settling
timeb, c, d
Settling band
≤ 6 cycles
≤ 4 cycles
−2.5%/+10% of IBR unit
maximum current
−2.5%/+10% of IBR unit
maximum current
a
The initial response from the type III WTG is driven by machine characteristics and not the control system. DC
component, if present, has an impact on response, which is driven by machine parameters and time of fault
occurrence. Even though the control system takes an action, it cannot control machine’s natural response. As such,
defining response time for type III WTGs is not necessary.
b
System conditions may require a slower response time, or IBR units may not be able to meet response times
noted in this table for certain system conditions. If so, greater response time and settling time are allowed with
mutual agreement between an IBR owner and the TS owner.
c
The DFT with a one-cycle moving average window is used to derive phasor quantities such as active, reactive,
positive-sequence, negative-sequence currents, etc. The time delay required for the DFT measurements is included
in the step response time and settling time specified in this table.
d
The specified step response time and settling time applies to both 50 Hz and 60 Hz systems.
Figure I.1 through Figure I.6 illustrate performance requirements specified in this clause. A three-phase fault
is applied at POM of the IBR plant containing type IV WTGs. In this example, the step response time is
40 ms, i.e., the final steady-state current is reached in 40 ms from initiation of a fault.
7.2.2.4 Consecutive voltage deviations ride-through capability 109
The IBR plant shall ride through multiple excursions outside of the continuous operation region with
exception of the conditions and situations specified below, for which the IBR plant may trip to protect
equipment integrity from the cumulative effects of successive voltage deviations:
109
The primary intent of voltage ride-through requirements for consecutive voltage deviations is for the IBR plant to ride through a
reasonable tripping and reclosing sequence associated with short-circuit faults on TS. Other causes for consecutive disturbances are
separate faults that might occur in a severe storm, or dynamic voltage oscillations that cyclically transition in and out of the continuous
operation region. The IBR plant is not expected to ride through opening and reclosing of a tie-line connecting the IBR plant to an
interconnecting TS.
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Associated Transmission Electric Power Systems

The IBR plant may trip for disturbances for which the cumulative duration of voltage deviations
within the applicable time window specified in 7.2.2.1 (i.e., 10 s or 3600 s) exceeds (i.e.,
undervoltages less than or overvoltages greater than) the ride-through durations specified in Table 11
or Table 12, as applicable.

The IBR plant may trip for more than four deviations of the applicable voltage at the RPA outside of
the continuous operation region within any 10-s period.

The IBR plant may trip for more than six deviations of the applicable voltage at the RPA outside of
the continuous operation region within any 120-s period.

The IBR plant may trip for more than ten deviations of the applicable voltage at the RPA outside of
the continuous operation region within any 30-min (1800-s) period.

The IBR plant may trip for any voltage deviation outside of continuous operation region that follows
the end of a previous deviation by less than 20 cycles of the system fundamental frequency.

The IBR plant may trip for more than two individual deviations of the applicable voltage at the RPA
below 50% of the nominal voltage (inclusive of zero voltage) within any 10-s period.

The IBR plant may trip for more than three individual deviations of the applicable voltage at the RPA
below 50% of the nominal voltage (inclusive of zero voltage) within any 120-s period.

For WTG-based IBR plants, individual IBR units (WTGs) may trip to self-protect for consecutive
voltage deviations that result in stimulation of mechanical resonances exceeding equipment limits.
Individual voltage deviations begin when the applicable voltage at the RPA becomes less than the lower limit
of the continuous operation region or greater than the upper limit of the continuous operation region.
Individual deviations end when the rms magnitude of the applicable voltage at the RPA, for previous onecycle period of the fundamental frequency, is within the continuous operation region.
The TS owner/TS operator should specify ride-through requirements for dynamic voltage oscillations that
may be stimulated by a TS fault, opening of a line, or tripping of a generator and that may cause the applicable
voltage to deviate outside the continuous operation region multiple times. The characteristic of dynamic
voltage oscillation may be specified by one or more of the following:

Upper and lower limits of the oscillating applicable voltage

Frequency of oscillation in the synchronous reference frame

Damping ratio of the oscillation
The consecutive voltage deviation ride-through capability of an isolated IBR interconnected to the TS via a
VSC-HVDC transmission facility may be limited by the energy absorption capability and thermal design of
the dc chopper in the VSC-HVDC line, as well as by the ability of fast control of active power production by
the isolated IBR. Refer to Annex M for an explanation.
The IBR owner of isolated IBRs that are interconnected to an ac transmission system via a dedicated VSCHVDC transmission facility shall inform the TS owner/TS operator of any limitations regarding the capability
of the combined IBR facility to meet the consecutive voltage deviations ride-through capability requirements
specified in this clause. IBR owner and TS owner/TS operator shall mutually agree on remedy measures,
which may include one or more of the following:

The dc chopper may be designed to absorb ICR for at least 2 s.

New control methods of the offshore ac-dc converter station that enable fast reduction of active power
production from isolated IBRs (e.g., WTGs) by changing the offshore ac network voltage.

Other means not specified.
As applicable, exception from specified consecutive voltage deviations ride-through capability shall be
permitted with mutual agreement between the IBR owner and TS owner/TS operator.
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Associated Transmission Electric Power Systems
7.2.2.5 Dynamic voltage support
NOTE—Dynamic voltage support is mandatory and has been specified in 7.2.2.3.4.
7.2.2.6 Restore output after voltage ride-through
The requirements specified in this subclause apply following system disturbances including faults on the TS.
Upon the applicable voltage returning to continuous operation region, from a mandatory operation region
or permissive operation region where the IBR plant performs ride-through in mandatory operation mode, the
IBR plant shall have capability to restore active power output to 100% of pre-disturbance level at an average
rate equal to 100% of ICR divided by specified active power recovery time. The default active power recovery
time shall be 1.0 s. The following exceptions apply:


If IBR plant capacity is reduced to no less than 90% of the pre-disturbance level, as per the exception
specified in 7.2.2.1, and/or if post-disturbance available active power is less than pre-disturbance
available active power then IBR plant shall have capability to restore active power output
proportional to available IBR plant capacity multiplied by post-disturbance available active power.
Examples:
i)
Post disturbance IBR plant capacity is 100% but available active power is 80% of predisturbance available active power: The IBR plant shall have capability to restore active
power output to 80% of pre-disturbance available active power.
ii)
Post disturbance IBR plant capacity is reduced to 92% and available active power is 100%
of pre-disturbance available active power: The IBR plant shall have capability to restore
active power output to 92% of pre-disturbance available active power.
iii)
Post disturbance IBR plant capacity is reduced to 95% and available active power is 90%
of pre-disturbance available active power: The IBR plant shall have capability to restore
active power output to 87.4% of pre-disturbance available active power.
For WTG-based IBR plants, for which the wind turbine blade pitch has been changed to reduce
overspeed due to the severity and duration of the voltage disturbance, shall have capability to restore
active power output to the maximum active power output available for altered pitch within 1.0 s, and
shall be capable to restore active power output to 100% of pre-disturbance level as soon as practical.
The active power recovery time shall be configurable within a range between 1.0 s and 10 s. The default
active power recovery time is 1 s; however, in weak grids, in order to reduce oscillatory behavior of the IBR
plant upon fault recovery and maintain system stability, it may be desirable to reduce the average rate of
active power recovery in consultation with the TS owner. Any modification of the recovery time from the
default value shall be based on a mutual agreement between the IBR owner and the TS owner. The time to
restore active power output shall be a target time with a tolerance that is the greater of ± 0.2 s or ± 10% of
configured active power recovery time in seconds and shall not be interpreted as a maximum time.
Upon the applicable voltage returning to continuous operation region from a permissive operation region
where the IBR plant performs ride-through in current blocking mode and once the IBR plant restarts exchange
of current with the TS, the IBR plant shall restore active power output as specified above.
Upon the applicable voltage returning to mandatory operation region from a permissive operation region
where the IBR plant performs ride-through in current blocking mode and once the IBR plant restarts exchange
of current with the TS, the IBR plant shall exchange current as specified in 7.2.2.3.4 and meet performance
requirements specified in 7.2.2.3.5.
Upon the applicable voltage returning to continuous operation region (as interpreted at the IBR unit
terminals), IBR units shall have capability to cease injection of incremental positive-sequence reactive current
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(∆IR-1) and incremental negative sequence reactive current (∆IR-2), per the performance requirements
specified in 7.2.2.3.5.
7.2.3 Transient overvoltage ride-through requirements
The IBR plant shall ride through transient overvoltage that do not exceed the fundamental-frequency
overvoltage ride-through requirements specified in 7.2.2.1 and for which the greater of individual phase-tophase or phase-to-ground instantaneous voltage magnitudes do not exceed the cumulative durations
(minimum time) specified in Table 14. The interpretation of cumulative duration in the context of
instantaneous voltage magnitudes is illustrated in the informative Figure 11. The cumulative duration shall
only include the sum of durations for which the instantaneous voltage exceeds the respective threshold over
a 1-min time window. 110
The voltages in Table 14 shall be per unit of the nominal instantaneous peak voltage at the RPA. For example,
in case of an IBR plant with RPA voltage of 230 kV phase-to-phase RMS, the phase-to-phase instantaneous
peak voltage is 325.3 kV
(( 230 3 ) × 2 ) .
( 230 × 2 )
and the phase-to-ground instantaneous peak voltage is 187.8 kV
Table 14 —Transient overvoltage ride-through requirements at the RPA
a
Voltagec
(p.u.) at the RPA
V > 1.80
V > 1.70
V > 1.60
V > 1.40
V > 1.20
Minimum ride-through time (ms)d
(design criteria)b
See footnotea
0.2
1.0
3.0
15.0
Appropriate surge protection shall be applied at the RPA as well as within the
IBR plant, including IBR unit terminals (POC), as necessary.
b
The minimum ride-through times specified in Table 14 apply to both 50 Hz
and 60 Hz systems.
c
Specified voltage magnitudes are the residual voltages with surge arresters
applied.
d
Cumulative time over a 1-min time window.
The intent of transient overvoltage ride-through requirements is to help ensure that the IBR plant does not
trip during switching events in the TS. An IBR unit should continue to inject current, but it does not have to
respond to transient overvoltage, i.e., enter reactive priority mode and/or change magnitude of current output.
If necessary, the IBR unit may operate in current blocking mode, when instantaneous voltage exceeds
1.2 p.u., to help ensure stable response that does not lead to tripping and to eliminate the IBR plant as a
possible cause for the overvoltage. If the IBR unit operates in the current blocking mode, it shall restart
current exchange in less than or equal to five cycles following instantaneous voltage falling below, and
remaining below, 1.2 p.u.
110
Cumulative duration is illustrated as follows:
Cumulative duration exceeding magnitude threshold is the sum of periods X, Y, and Z
Voltage (p.u. of nominal peak)
X
Z
Example
± magnitude
thresholds
Y
One fundamental-frequency period
Time
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The IBR unit’s TOV ride-through capability may differ from the IBR plant’s TOV ride-through requirement
specified in this subclause. The IBR plant design should coordinate an IBR unit’s TOV ride-through
capability with surge protection implemented within the IBR plant while allowing the IBR plant to meet
specified TOV ride-through requirements.
Figure 11 —Transient overvoltage ride-through requirements for IBR plant (informative)
7.3 Frequency
7.3.1 Mandatory frequency tripping requirements
Requirements as specified in 9.1 and 9.2 shall apply.
7.3.2 Frequency disturbance ride-through requirements
7.3.2.1 General requirements and exceptions
The default reference point of applicability (RPA) for frequency disturbance ride-through requirements shall
be the POM. Frequency shall be calculated accurately including appropriate filtering to take any control
and/or to execute any protection function on the fundamental frequency component as prescribed in 4.4.
The capability and performance required of an IBR plant during frequency disturbances is specified in this
clause. The frequency disturbance ride-through performance requirements specified in this clause shall apply,
with the exception of the primary frequency response performance requirements specified in 7.3.2.3.2 and
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Associated Transmission Electric Power Systems
7.3.2.3.4, when voltage is within the continuous operation region or mandatory operation region specified
in 7.2.2. 111, 112
An IBR plant shall be designed to provide the frequency disturbance ride-through capability specified in this
subclause. Any tripping of the IBR plant, or other failure to provide the specified ride-through capability, due
to IBR unit self-protection as a direct or indirect result of a frequency disturbance within a ride-through region
shall constitute non-compliance with this standard.
Exception: The IBR plant shall satisfy requirements of this subclause unless tripping of the IBR plant is
required to clear faults either internal to the IBR plant, on the interconnection system (IBR tie line), or any
portion of the TS which may provide sole connectivity between the IBR plant and the TS.
The minimum capability shall be no less than the continuous operation or mandatory operation capability
regions shown in Figure 12, and with parameters defined in Table 15. The TS owner may require broader
capability.
Figure 12 —Frequency ride-through capability requirements for IBR plant
Table 15 —Frequency ride-through capability for an IBR plant (see Figure 12)
Frequency range
(Hz)
Percent from fnom
Minimum time (s)
(design criteria)
Operation
f1, f4
+3, −5
299.0 (t1)
Mandatory operation
f2, f3
+2, −2
∞
Continuous operation
7.3.2.2 Continuous operation region
When the applicable frequency is within the required continuous operation region, as defined in Table 15,
the IBR plant shall exchange active and reactive power with the TS within its IBR continuous rating (ICR)
and within the volts per hertz capability limits of IBR units, supplemental IBR devices, and transformers as
This requirement considers that frequency should not be calculated, nor used for trip/no-trip decisions, during a fault. Namely, as is
commonly done on other equipment under-frequency relays, that is the frequency trip may be disabled during a voltage dip.
112
Frequency variation may occur during voltage disturbances and vice-versa.
111
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specified by the applicable standards. 113 In addition, the IBR plant shall operate in accordance with PFR
and/or FFR control requirements as applicable.
7.3.2.3 Frequency disturbances within the mandatory operation region
7.3.2.3.1 Low-frequency ride-through capability
During temporary frequency disturbances, for which the applicable frequency is less than f3 and greater than
or equal to f4 (mandatory operation region for low-frequency ride-through), and having a cumulative duration
below f3 of less than 299 s in any 10-min period, and within the volts per hertz capability, the IBR plant shall
be capable to ride through and shall have the capability to:

Maintain synchronism with the TS.

Meet the requirements of 6.1 and/or 6.2 as applicable or maintain pre-distubance active power output,
or maintain active power output as required by the TS owner.

Maintain its reactive power output. 114
7.3.2.3.2 Low-frequency ride-through performance
During low-frequency ride-through, the IBR plant shall operate in the required mandatory operation region
as specified in Figure 12 and Table 15 per performance requirements specified in this subclause.
During temporary low-frequency disturbances, for which the applicable frequency is within the required
mandatory operation region and within the volts per hertz capability, the IBR plant shall:

Maintain synchronism with the TS.

Continue to exchange current with the TS and shall not initiate a protective function. Active and
reactive current oscillations that are positively damped are acceptable.

As applicable, modulate active power to mitigate the underfrequency conditions as specified in 6.1
or 6.2. IBR plant operating below available active power levels are subject to the requirements of
this standard. 115
An IBR unit and an IBR plant may protect itself or may ride-through when the frequency is less than f4.
7.3.2.3.3 High-frequency ride-through capability
During temporary frequency disturbances, for which the applicable frequency is greater than f2 and less than
or equal to f1 (mandatory operation region for high-frequency ride-through), and having a cumulative
duration greater than f2 for less than 299 s in any 10-min period, and within the volts per hertz capability, the
IBR plant shall be capable to ride through and shall have the capability to:

Maintain synchronism with the TS.

Meet the requirements of 6.1 as applicable or maintain pre-distubance active power output, or
maintain active power output as required by the TS owner.

Maintain its reactive power output.114
113
Applicable standards may include, but are not limited to, IEEE Std C50.12™ [B60], IEEE Std C50.13™ [B61], IEEE Std C57.12™
[B62], and IEC 60034-3 [B30], section 7.3.
114
IBR plant may adjust voltage (reactive power) during frequency ride-through to stay within the V-f limits specified in the standard.
115
Pre-curtailment or other measures to provide frequency response reserve may be included in contractual agreements and
interconnection agreements, which are outside the scope of this standard. The intent of the requirement in this standard is for the IBR
plant to only have the control capability to provide frequency response when the reserve exists, either due to specific contractual
arrangements, dispatch control, or when curtailment exists for other reasons. Direction of active power can be negative (charging) for
IBR plants with energy storage, e.g., return to frequency reduction via charging through droop or dispatch control, if operating for that
purpose prior to trip.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
7.3.2.3.4 High-frequency ride-through performance
During high-frequency ride-through, the IBR plant shall operate in required mandatory operation region as
specified in Figure 12 and Table 15 per performance requirements specified in this clause.
During temporary high-frequency disturbances, for which the applicable frequency is within the required
mandatory operation region and within the volts per hertz capability, the IBR plant shall:

Maintain synchronism with the TS.

Continue to exchange current with the TS and shall not initiate a protective function. Active and
reactive current oscillations that are positively damped are acceptable.

As applicable, modulate active power to mitigate the overfrequency conditions as specified in 6.1
and/or 6.2.
An IBR unit and an IBR plant may protect itself or may ride-through when the frequency is greater than f1.
7.3.2.3.5 Rate of change of frequency (ROCOF) ride-through
Within the mandatory operation region and continuous operation region (frequency range and corresponding
cumulative duration, time), the IBR plant shall ride through and shall not trip for frequency excursions having
an absolute rate of change of frequency (ROCOF) magnitude that is less than or equal to 5.0 Hz/s. As
specified in 4.3, the ROCOF shall be the average rate of change of frequency over an averaging window of
at least 0.1 s. Upon mutual agreement between the TS operator and the IBR operator, the IBR plant may be
required to ride-through and not trip for higher ROCOF levels.
7.3.2.4 Voltage phase angle changes ride-through
The IBR plant shall ride through positive-sequence phase angle changes within a sub-cycle-to-cycle time
frame of the applicable voltage of less than or equal to 25 electrical degrees. 116
In addition, the IBR plant shall remain in operation for any change in the phase angle of individual phases
caused by occurrence and clearance of unbalanced faults, provided that the positive-sequence angle change
does not exceed the forestated criterion. Active and reactive current oscillations in the post-disturbance
period that are positively damped shall be acceptable in response to phase angle changes. Current blocking
in the post-disturbance period shall not be permitted.
7.4 Return to service after IBR plant trip
The return to service criteria for the IBR plant are specified in 4.10.2.
116
Typically caused by line switching (in or out), load rejection, etc., and depends on pre- and post-network flows.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
8. Power quality
8.1 Limitation of voltage fluctuations induced by the IBR plant
8.1.1 General
The IBR plant shall not create unacceptable rapid voltage changes or flicker at the RPA. The default RPA for
this subclause shall be the POM.
8.1.2 Rapid voltage changes (RVC)
NOTE—This subclause is not intended to address issues associated with slow voltage variations, which can be caused
by cloud shadow passage, wind speed changes, etc.
8.1.2.1 Frequent RVC
The IBR plant shall not cause RVC at the RPA to exceed 2.5% of nominal voltage. The method for defining
compliance with this RVC requirement shall be as specified in IEC 61000-4-30:2015/AMD1:2021 or later.
Any exception to the limits is subject to approval by the TS owner with consideration of other sources of
RVC within the TS.
These RVC limits shall apply to sudden changes due to frequent energization of transformers, frequent
switching of capacitors, or from abrupt output variations caused by IBR plant misoperation. These RVC
limits shall not apply to infrequent events such as switching, unplanned tripping, or transformer energization
related to commissioning, fault restoration, or maintenance.
8.1.2.2 Infrequent RVC
For infrequent events, Figure 13 illustrates the RVC limit characteristics, which include:

The minimum voltage, as measured at the RPA, shall be no less than 0.88 × the initial voltage.

After 4 cycles, the minimum voltage shall be no less than 0.9 × the initial voltage.
Figure 13 —Minimum acceptable voltage due to infrequent events
The initial RMS voltage, VO, and final RMS voltage, VF, shall be within the acceptable nominal voltage
range. The characteristics of the measured voltage at the RPA during the infrequent event shall be equal to
or above the per unit values represented by the line beginning at t0 and ending at t = 2 s.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
8.1.3 Flicker
The IBR plant contribution (emission values) to the flicker, applied at the RPA, shall not exceed the greater
of the limits listed in Table 16 and the individual emission limits determined as per the procedure described
in IEC TR 61000-3-7 Section 9. 117 Any exception to the limits may be allowed if accepted by the TS owner
with consideration of other sources of flicker within the TS.
Table 16 —IBR plant flicker emission limits at the RPAa
EPst
EPlt
0.35
0.25
95th percentile value of the measurements should not
exceed the emission limit based on a one-week
measurement period.
a
Assessment and measurement methods for flicker are defined in IEEE Std 1453™ (subclause 6.3) and IEC
TR 61000-3-7 (subclause 6.3). In addition, the following shall apply:

Equipment other than an IBR unit, i.e., a supplemental IBR device, may be used to mitigate the flicker
induced by an IBR plant.

EPst is the emission limit for the short-term flicker severity, Pst. If not specified differently, the Pst
evaluation time shall be 600 s.

EPlt is the emission limit for long-term flicker severity, Plt. If not specified differently, the Plt
evaluation time is 2 h.

Plt can be calculated by using Equation (1).
Plt = 3
1
12
12
∑P
i =1
3
st i
(1)
where (i = 1, 2, 3, ...) are consecutive readings of the short-term severity Pst

The requirements shall be met at the RPA irrespective of the voltage level.
8.2 Limitation of harmonic distortion
The requirements in this subclause shall apply to the IBR plant and the default reference point of applicability
(RPA) shall be the POM. Prior to the interconnection of the IBR plant, the TS owner and IBR owner shall
coordinate the creation of a baseline of the TS voltage harmonics at the RPA for future comparison.
The measurement methodology shall follow IEC 61000-4-7 Class I and IEC 61000-4-30 Class A and the
statistical methodology for measuring harmonic and interharmonic values in this requirement shall follow
IEEE Std 519™.
Harmonic measurements and adherence to the limits shall be applicable at the time of commissioning of the
IBR plant. Applicability of the requirements after commissioning may depend on TS owner requirements
subject to the general remarks and limitations in 1.4. 118
For example, if the emission limit, EPst, is determined as a value of 0.25, a value of 0.35 needs to be specified.
Subclause 1.4 clarifies that the requirements specified in this standard are intended to apply over the lifetime of the IBR plant and
that, where the TS operating and network conditions change significantly enough that changes in the IBR plant may become necessary
117
118
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
The current harmonic limits specified in 8.2.1 shall be applicable only if the TS voltage harmonics prior to
the IBR plant connection are below the limits specified in IEEE Std 519; however, the IEEE 519 voltage
limits shall not apply to the IBR plant unless mutually agreed upon between the TS owner and IBR owner.
The TS owner should not deny an IBR plant interconnection due to the pre-existing level of TS harmonic
voltage distortion. 119
8.2.1 Harmonic current distortion
Harmonic current distortion, with the exception of the 2nd, 4th, and 6th order harmonic current distortion,
interharmonic current distortion, and total rated-current distortion (TRD) at the RPA shall not exceed the
limits stated in the following paragraph and in Table 17. 120 Current distortion at the 2nd, 4th, and 6th harmonics
shall be the lesser of the values specified in Table 17 and Table 18, and as stated in the following paragraphs.
Any aggregated harmonic current distortion between h ± 5 Hz, where h is the individual harmonic, shall be
limited to the associated harmonic or h limit in Table 17. Any aggregated interharmonics current distortion
between h + 5 Hz and (h + 1) − 5 Hz shall be limited to the lesser magnitude limit of h and h + 1 harmonic
or in Table 17.
Current distortion limits shall be absolute, inclusive of any harmonic currents due to the harmonic sources in
the TS and harmonic current due to the IBR plant.
Upon mutual agreement between the TS owner and the IBR owner, the IBR plant may have current distortion
in excess of limits specified in Table 17 and Table 18, whichever applicable, such as when it is used as an
active filtering device or when passive filtering exists in the IBR plant, or where harmonic voltage distortion
at the RPA does not exceed limits specified by the TS owner under 8.2.2.
Table 17 —Maximum current distortion in percent of rated current (Irated) 121, 122
RPA LL voltage
(kV)
≤ 69
69.001 to 161
> 161
Individual harmonic order h
h < 11
11 ≤ h < 17
17 ≤ h ≤ 50
percent (%)
percent (%)
percent (%)
4.0
2.0
1.5
2.0
1.0
1.0
1.5
1.0
1.0
Total rated current
distortion (TRD)
percent (%)
5.0
2.50
2.0
Table 18 —Maximum current distortion at certain even harmonics
in percent of rated current (Irated) 123
h=2
percent (%)
1.0
Certain even harmonic order h
h=4
h=6
percent (%)
percent (%)
2.0
3.0
to ensure reliable operation of the IBR plant, equitable remedy measures are coordinated between the TS owner and the TS operator,
and the IBR owner and the IBR operator.
119
CIGRE TB-754 [B15] discusses ac side harmonics and provides appropriate harmonic limits for VSC HVDC as well as IBR.
120
Note that Table 17 differs from any table in IEEE Std 519. In this standard, the new term total rated-current distortion (TRD) was
introduced, which includes all frequencies, and is used instead of TDD (in Table 17).
121
The values specified in this table differ from the IEEE Std 519-2014 requirements. The values in this table are closer to the original
limits that were in the IEEE Std 519-1992 version. The change between IEEE Std 519-1992 and IEEE Std 519-2014 was made so that
resistive loads can meet the requirements if the system voltage distortion is below the recommend harmonic guidelines.
122
Potential future revisions of this standard may differentiate the specified individual harmonic current limits not only based on voltage
class but also based on TS characteristics like short-circuit ratio at the RPA, etc.
123
These values are identical to those specified in IEEE Std 1547-2018 for certain even harmonics.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
An IBR plant shall not be subjected to individual harmonic current limits if the harmonic currents do not
cause the respective individual harmonic voltages (hth order) at the RPA to increase using short time harmonic
measurements on a weekly 95th percentile basis, i.e., the hth harmonic voltage does not increase upon
interconnection of an IBR plant. 124, 125
The current limits are applicable only if the negative sequence component of the fundamental-frequency
applicable voltage at the RPA (as defined in 4.2) is less than 2% of the nominal voltage. If negative sequence
component of the voltage exceeds 2% of the nominal voltage, harmonic current limits shall increase
proportionally at the rate of 100% for each 1% increase in negative sequence voltage exceeding 2%. 126
With mutual agreement between TS owner and IBR owner, enforcement of these current limits shall consider
the achievable accuracy of the measurement techniques, including the accuracies of current transducers and
instrumentation.
The 95th percentile value of the harmonic measurement shall not exceed the emission limit based on a oneweek measurement period.
Equipment other than an IBR unit, i.e., a supplemental IBR device, shall be allowed to mitigate the harmonic
current distortion induced to the TS by an IBR plant.
The total rated current distortion (TRD) in Table 17, which includes harmonic distortion, interharmonic
distortion, and noise is defined by Equation (2):
=
%TRD
2
I rms
− I12
I rated
(2)
× 100%
where
I1
is the fundamental-frequency current as measured at the RPA
Irated is the IBR plant rated current capacity based on IBR plant MVA rating at the RPA (as stated in the
interconnection request; may be equal to ICR)
Irms is the root-mean-square of the IBR plant current, inclusive of all frequency components up to 50th
order, as measured at the RPA; measurement of harmonics to the 50th order requires meters compliant
to IEC 61000-4-30 Class A
8.2.2 Harmonic voltage distortion
This standard does not specify harmonic voltage distortion limit values. 127
The TS owner should 128 specify voltage harmonic limits for an IBR plant at the reference point of
applicability (RPA) subject to the general remarks and limitations stated in 1.4. If the TS owner specifies
such limits,
For example, if the IBR plant has a shunt harmonic filter installed, this can increase harmonic current flow from the TS into the IBR
plant across the POI from external distortion sources in the TS, yet beneficially reduces voltage distortion at the POM at the filter’s
tuned frequency(s).
125
Another example is an IBR plant that may inject controlled harmonic currents to mitigate harmonic voltage distortion in the TS.
126
For example, the current limit for the VLL > 161 kV at the RPA and h < 11 is specified as 1.5% in Table 17. When the voltage
unbalance factor is 3%, the increased harmonic current limit is calculated as follow: 1.5% × [1 + (3 − 2)] = 3%.
127
At the time of development of this standard, there is no consensus on industry accepted harmonic voltage distortion limits. Harmonic
voltage limits or requirements are recommended to be established in a possible future revision of this standard following more research
and industry discussion.
128
The use of the term should indicates a recommended practice. The purpose of this sentence is to encourage the TS owner to use the
informative recommended practices on methods to establish harmonic voltage distortion requirements and associated verification
124
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Associated Transmission Electric Power Systems
a)
The IBR plant may, based on mutual agreement between the TS owner and the IBR owner, not be
subjected to the individual harmonic current limits specified in 8.2.1 and
b)
The IBR owner should coordinate remedy measures, as needed, with the TS owner to meet the
harmonic voltage distortion requirements.
For informative recommended practices on methods to establish harmonic voltage distortion requirements
and associated verification evaluation methods, refer to Annex E. 129
8.3 Limitation of overvoltage contribution
The default reference point of applicability (RPA) for the overvoltage contribution requirements of an IBR
plant shall be the point of measurement (POM). The curves referred in 8.3.1 and 8.3.2 do not necessarily
imply protective action or control action, but are performance criteria established via design.
8.3.1 Limitation of cumulative instantaneous overvoltage 130
The IBR plant shall not cause the instantaneous magnitude of the applicable voltage at the RPA to exceed
the maximum magnitudes and cumulative durations specified in Table 14. The cumulative duration shall only
include the sum of durations for which the instantaneous voltage exceeds the respective threshold over a
1-min time window, after which it resets. 131, 132 This requirement shall not apply to the situations where the
IBR becomes isolated from the TS.
8.3.2 Limitation of overvoltage over one fundamental frequency period 133
In addition to the instantaneous overvoltage limits specified in 8.3.1, the IBR plant shall not cause the rootmean-square (RMS) magnitude of the applicable voltages at the RPA to exceed the maximum magnitudes
and cumulative durations specified in Figure 14, cumulative over a 1-min period, after which it resets. For
this requirement, the RMS voltage shall be based on a moving window having a time duration equal to one
fundamental-frequency period.
evaluation methods provided in Annex E to specify harmonic voltage limits until a potential future revision of this standard includes
consensus values.
129
See also footnote 119.
130
These performance requirements are intended to be met by inverter design, and not by control action.
131
An example of the cumulative duration is provided in the figure below.
Cumulative duration exceeding magnitude threshold is the sum of periods X, Y, and Z
Voltage (p.u. of nominal peak)
X
Z
Example
± magnitude
thresholds
Y
One fundamental-frequency period
Time
132
133
The accumulation of instantaneous voltage exceeding thresholds can occur over multiple fundamental frequency cycles.
These performance requirements are intended to be met by inverter design, and not by control action.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Figure 14 —RMS overvoltage limits for an IBR plant at the RPA
NOTE—For cumulative durations greater than or equal to 70 cycles, the RMS voltage shall not exceed 1.1 p.u.
9. Protection
The following subclauses specify the protective function 134 requirements for an IBR plant. The scope and
limitations of this clause is described in 1.4. 135 The protective functions of this clause shall be coordinated
with those of the TS, where applicable. Refer to Annex F for further information.
Protections applied to IBR plant auxiliary load shall not limit the ability of the IBR plant to meet the ridethrough performance requirements.
9.1 Frequency protection
This standard does not require frequency protection for equipment in an IBR plant. However, if an IBR owner
employs this protection element, then it shall comply with the requirements specified in this section.
If there is a specific need to protect the IBR plant, the applied IBR frequency protection shall allow the IBR
plant to meet its ride-through requirements. The TS owner and the IBR owner shall coordinate the IBR plant
frequency protection with the TS frequency protection, if present, and the underfrequency load shedding
(UFLS) scheme in the area.
134
IEEE Std C37.2™-2008 [B57] may provide useful standard electrical power system device function numbers, acronyms, and contact
designations.
135
Requirements for, or limitations to the deployment and configuration of protection functions by the TS owner on their side of the
interconnection system or at the POI are outside the scope of this standard.
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Associated Transmission Electric Power Systems
9.2 Rate of change of frequency (ROCOF) protection
This standard does not require rate of change of frequency (ROCOF) protection in an IBR plant. In cases
where ROCOF protection is used to protect specific equipment within the IBR plant, it shall not impede the
IBR plant from meeting the ride-through requirements of this standard inclusive of ROCOF ride-through
requirements. ROCOF should be based on a change of frequency averaged over sufficient time to reject
spurious frequency measurements caused by distortion and transients.
9.3 AC voltage protection
Any applied IBR voltage protection shall allow the IBR plant to meet its ride-through requirements. The TS
owner and the IBR owner shall coordinate the IBR plant voltage protection with the TS voltage protection, if
present, and the undervoltage load shedding (UVLS) scheme in the area.
All instantaneous overvoltage protection used within the IBR plant shall use filtered quantities (Schweitzer
and Hou [B105]) to reduce the possibility of misoperation while providing protection to the desired
equipment and system. Any instantaneous overvoltage protection(s) that has the possibility of disrupting the
power output of the entire plant shall use at least one cycle (of fundamental frequency) measurement window
to reduce such possibility and the related impact on the TS. Protection margin shall be coordinated with the
TS owner, wherever applicable.
Where instantaneous overvoltage protection is applied on IBR unit(s), it shall:

Be coordinated with transient overvoltage capability of IBR units

Be coordinated with any surge protection implemented within the IBR plant and at the RPA

Allow the IBR plant to meet its transient overvoltage ride-through requirements specified in 7.2.3
9.4 AC overcurrent protection
AC overcurrent protection is applicable to phase and sequence quantities. This standard does not require
overcurrent protection for every piece of equipment in an IBR plant. However, if an IBR owner employs this
protection element, then it shall not limit the facility’s ride-through capability as required in this standard and
shall be coordinated with other protection schemes that are applied on the TS, while maintaining adequate
protection in the IBR plant.
All instantaneous overcurrent protection used within the IBR plant shall use filtered quantities (Schweitzer
and Hou [B105]) to minimize the possibility of misoperation while providing protection to the desired
equipment and system. Any instantaneous overcurrent protection(s) that has the possibility of disrupting the
power output of the entire plant shall use at least one cycle (of fundamental frequency) measurement window
to reduce such possibility and the related impact on the TS. The ac overcurrent protection shall be coordinated
with the TS owner, wherever applicable.
9.5 Unintentional islanding protection
Any unintentional islanding protection schemes used by the IBR units or the IBR plant shall not limit the IBR
plant’s ride-through capabilities specified in this standard. 136
136
IBR units may use inbuilt active unintentional islanding protection schemes to protect themselves and equipment in the IBR plant,
for example, when any part of an IBR plant’s collector system becomes isolated due a fault inside the IBR plant.
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Associated Transmission Electric Power Systems
If islanding of the IBR plant with any portion of the TS is not allowed by the TS owner, unintentional islanding
protection shall be implemented, in accordance with the TS owner requirements.
9.6 Interconnection system protection
The IBR plant shall implement protection for the interconnection system in accordance with the requirements
of the TS owner and/or the requirements of the owners of electrically joined facilities. This protection shall
be coordinated with the TS protection system. Protection schemes shall not limit the IBR plant’s ride-through
capability with the following exceptions:

Faults within the interconnection system

Faults within protection zones identified by the TS owner that provide sole connectivity of the IBR
plant to the TS

Faults within the IBR plant that cannot be cleared except by disconnecting the IBR plant
10. Modeling data
Some performance requirements, such as voltage ride-through performance requirements, for which the RPA
is at the point of measurement (POM), cannot be verified based on type tests or production tests of individual
equipment within an IBR plant and/or commissioning tests of the IBR plant. The IBR plant design evaluation
using models and simulations is necessary to verify, to the extent feasible and possible, that the IBR plant
meets performance requirements, especially during various stages of interconnection studies and
commissioning. As detailed in 12.2.3, the IBR plant design evaluation may be performed by the IBR owner,
TS operator, TS owner, third-party consultants, or jointly by these parties. It is critical that models provided
for IBR plants are accurately structured and parameterized as well as reflect the actual installed equipment in
the field for reliability study purposes and to help ensure reliability of the BPS. In addition to the IBR plant
design evaluation, models are also necessary to perform various system studies.
It should be noted that almost all forms of models, even detailed EMT (electromagnetic transient) models of
IBR plants, invariably have certain necessary approximations and limitations. For example, even in an EMT
model, the full collector system details are almost never modeled for various reasons. Thus, no model can
predict with absolute certainty the response of every individual IBR unit inside the IBR plant. As such, the
results of simulations should be understood in this context. As an example, fault ride-through tests performed
in simulations may show the entire plant rides through, while in real life the exact same event may result in
a small number of IBR units tripping in a plant with tens or hundreds of IBR units. This is because the collector
system is typically equivalenced and even if it were modeled in all its details, one cannot predict the exact
status (e.g., wind speed at each turbine) of each IBR unit for a given condition. In short, modeling is not, nor
will it ever be, perfect. For approximations that are made while developing the models, a technical reference
that provides the relevant background and justification should be cited. If such a reference(s) is not available,
a detailed explanation related to the said approximations should be provided. In either case, the resultant
model should be shown to provide a verified behavior.
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Upon request from the TS operator and TS owner, the IBR owner shall provide:
a)
Verified IBR plant–level models, including a steady-state power-flow model, positive-sequence
(fundamental-frequency) 137 stability dynamic model 138 (user written 139 and/or generic 140), an EMT
model, short-circuit and harmonics models, to perform IBR plant design evaluation and system
studies. If necessary, the TS operator and TS owner may request additional types of models from the
IBR owner with proper justification.
b)
Documentation detailing development process and verification of these models.
c)
Documentation with brief explanation of control strategy.
Some common practices to develop verified models is outlined below, but may vary among original
equipment manufacturers (OEMs). The TS owner or TS operator may specify model verification
methodology for interconnecting IBR plants. 141

Non-aggregated IBR unit EMT model—This model may be developed based on actual code and may
be verified with type and/or hardware-in-the-loop (HIL) test results. 142

Supplemental equipment, including supplemental IBR device, EMT model—This model is verified
with type and/or HIL test results. 143

Aggregated plant-level EMT model—The IBR unit EMT model and EMT models of any
supplemental equipment within IBR facility is used to develop the aggregated plant-level EMT
model. The collector system within the IBR facility can be represented with an equivalent.

IBR unit stability 144 dynamic (user written and/or generic), short-circuit, etc., models—This model
is verified against non-aggregated IBR unit EMT model. This model includes converter and
respective electrical control models.
137
The major stability planning software tools presently used in North America, and many other places in the world, use phasor
(fundamental-frequency) representations, with the transmission network modeled as a constant impedance matrix, such that the lumped
impedance of all passive elements is provided as the effective positive-sequence (fundamental-frequency) impedance. These tools are
referred to as positive-sequence (fundamental-frequency) programs. There are, however, some software tools that go one step further
and model the network in greater detail, allowing full sequence representation for three-phase phasor (fundamental frequency) analysis.
In both these cases, the dynamics models for the controllers and devices being discussed are essentially the same. The primary difference
is in the way the network model is developed and interacts with the dynamic model. Finally, note that positive-sequence (fundamentalfrequency) modeling tools are sometimes called “RMS” tools, but that is not an accurate description and is not used as a description or
label for such simulation tools in this standard.
138
The TS operator, TS owner, IBR owners, and OEMs are encouraged to work jointly to determine the type of model (user-written,
generic, or both) for an IBR plant design evaluation. Although the scope of this requirement is for IBR plant design evaluation only, the
need of models for various local and interconnection-wide system studies should also be considered.
139
The user-written model contains more specific, nuanced control information than a generic model. The user-written (and presumably
more detailed) model may be necessary for the interconnection process. The TS operator and TS owner need to know how the IBR
functions in the transient time frame, especially when concerned about a very specific, focused area.
140
The generic model is usually used for interconnection-wide studies because the focus is on the entire interconnection. Accuracy may
be compromised due to generic nature of the model. It may not be possible to map all the parameters of generic models to actual controls
and protection settings. If so, the IBR owner, the respective OEM(s), TS owner, and TS operator are encouraged to jointly work to
identify and document any shortcomings of the generic model.
141
This standard specifies what type of validated and verified models be provided in the interconnection process. IEEE P2800.1 or IEEE
P2800.2 that are under development at the time of this standard’s adoption may specify how the model validation and verification
methods be conducted.
142
It is likely that a certain type (vintage, model, etc.) of converter and respective controls are used in multiple products. For example,
a WTG with active power rating ranging from 4.0 MW to 5.0 MW may use the same converter. If so, a verified EMT model of this
converter may be used to represent all WTGs that utilize this converter. A similar approach could also be used for inverters in PV solar
and battery energy storage system (BESS)–based resources.
143
Due to the size and custom design nature of HVDC and some FACTS and other large converters, model verification based on type
tests, prior to commissioning, is not possible. Even during the commissioning, it is not possible to perform all necessary dynamic
performance tests, since such tests cause severe stress on the ac network. Therefore, dynamic performance tests and model verification
are usually done by HIL tests with original converter control hardware. A highly reliable EMT model could be produced by using an
actual control code implemented in a hardware in conjunction with, or instead of, HIL test results. The use of an actual control code in
EMT models may allow for reduction in the number of HIL tests that otherwise needs to be conducted to produce a verified model.
144
Stability model refers to models used in fundamental-frequency positive-sequence software platforms for stability analysis.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems

The plant controller aspect of the stability model is typically verified or calibrated with plant
commissioning test results.
In case of an IBR plant to be built in the future, it is understood that as-built verified models only become
available once the IBR plant is built or closer to being commissioned. However, during the interconnection
process, the IBR owner shall make every effort possible to provide credible models to TS owner and TS
operator for various studies.
During the interconnection process or once the IBR plant is operational, modifications to controls that change
the response of the IBR plant or IBR units as defined within this standard shall be mutually agreed upon
between TS operator/TS owner and the IBR owner. The IBR owner shall provide updated models to TS owner
and TS operator according to a schedule determined by the TS owner or TS operator.
Once the IBR plant is operational, system event data could be used to verify various plant-level models.
When suitable event data are available and used to verify plant-level models, it is expected that the
performance of the IBR plant during an event may not exactly match with the one observed in simulations. 145
If so, engineering judgement is necessary in determining if the IBR plant meets the performance requirements
of this standard. In case where simulated performance of the IBR plant does not closely match with the
performance observed during an event as mutually determined by IBR owner and TS owner/TS operator, the
IBR owner shall provide updated models to TS owner and TS operator according to a schedule determined
by the TS owner or TS operator.
Depending on the type of study and the level of modeling required, different types of modeling data are
required. Annex G provides a list of the data recommended in each category of models.
11. Measurement data for performance monitoring and validation
To aid with performance monitoring, event analysis, and disturbance-based model validation (NERC
Reliability Guideline [B75]), the IBR plant shall take measurements at specified points throughout the
resource, from individual IBR units to the POM, using various technologies available. The data type,
measurements/data point, recording rate, duration of those data, and retention of those data are specified in
Table 19. Except for any confidential data in the “inverter fault codes and dynamics recordings” category as
defined in this clause, the IBR owner shall make these data available to the TS owner/TS operator, for event
analysis, performance monitoring or model validation. Availability of the excepted “inverter fault codes and
dynamic recordings” data to the TS owner/TS operator shall be by mutual agreement. Where this excepted
data are not made available to TS owner/TS operator, the IBR owner shall perform their own analysis of
significant TS events as requested by TS owner/TS operator and share findings with the TS owner/TS
operator. The IBR plant’s operational measurement data for exchange with TS operator, load balancing
entity, regional reliability coordinator, and markets in which it operates to facilitate integration in the electric
system is specified in 4.6.
It is expected that the regional regulatory requirements require the IBR owner to report any unplanned change
in operating and/or control mode to the TS operator in a timely manner.
All measured data, including status log of plant equipment (breakers, transformers, reactive compensation
devices, etc.) shall be time synchronized to Coordinated Universal Time (UTC). Time synchronization design
is discussed in IEEE Std 2030.101™. All IBR plant–level monitoring devices (sequence of event recorder,
digital fault recorder, dynamic disturbance recorder, and power quality meter) shall be synchronized to UTC
with ± 1 µs time accuracy, preferably using IEEE 1588–compliant devices, that implement either the IEEE
C37.238 or IEC/IEEE 61850-9-3 application profiles intended for the utility industry. Alternatively, time
synchronization using technologies based on unmodulated IRIG-B may be applied, but requires additional
145
For model verification using an event data, the grid and IBR plant should match pre-event operational conditions to the extent possible
in simulations.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
implementations beyond standard IRIG-B to achieve specified level of time accuracy. The IBR unit–level
monitoring devices shall be synchronized to UTC with ± 100 µs time accuracy.
Where applicable, all collected data should follow requirements of the IEEE Standard Common Format for
Transient Data Exchange (COMTRADE) or the IEEE Power Quality Data Interchange Format (PQDIF).
COMTRADE files shall be provided as specified in IEEE Std C37.111™-1999, IEEE Std C37.111™-2013,
or later. 146 PQDIF files shall be provided as specified in IEEE Std 1159.3™-2003 or IEEE Std 1159.3™2019, or later.
The measured data shall meet requirements specified in 4.4 as noted in Table 19.
A single file with a CFF extension should be provided instead of multiple component files to facilitate better management and
archiving of data.
146
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147








All breaker statuses, including change of status log
Shunt (dynamic or static) reactive compensation device
statuses
Substation transformer status (main step-up and
collector system)
Status of on load tap changer
Medium-voltage collector system statuses
Status of individual IBR units
Time stamp
Time synchronization (e.g., GPS status word) or status
of the GPS clock signal
Signals
 External control signals from the TS operator (BA,
RTO, RC, etc.)
 External automatic generation control signals
 Active and reactive power commands sent to IBR units
Measurements
 Point of measurement voltage and medium-voltage
collector system voltages
 Point of measurement frequency
 IBR plant active and reactive power output
 IBR units active and reactive power output of
individual 147
 Shunt dynamic device reactive power output
The plant SCADA system is often a lower resolution repository
of information that, at minimum, shall include the following
data points:
Measurement/data points (as applicable)
Static, as
changed
One record
per s
Recording
rate
1 year
1 year
Retention
NA
One year
Duration
Not applicable
Subclause 4.4,
Table 1
Measurement
(as applicable)
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Variables like commands may be only recorded when the value is changed and not at a specified sampling rate.
Plant equipment status
(tabular log file)
Plant SCADA data
(CSV file)
Provision data type
Table 19 —Measurement data—type, points, sampling rate, retention and duration
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
148
Digital fault recording
(DFR) data
(COMTRADE format and
tabular log file)
≥ 128
samples per
cycle,
triggered
90 days
90 days
1 year
Static, as
changed
Static, as
changed
Retention
Recording
rate
5s
COMTRAD
E data, (split
between prefault and
post-fault
data needs to
be mutually
agreed upon
with the TS
owner/TS
operator)
NA
NA
Duration
Subclause 4.4,
Table 2
Not applicable
Not applicable
Measurement (as
applicable)
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For IBR units that use standardized settings specified in IEEE Std 1547-2018, the IEEE 1547.1/EPRI specified “Common File Format for DER Settings Exchange and Storage” [B18] may be used.
This data shall be captured for at least the plant-level (e.g., at
the point of measurement) response to BPS events. It is
typically high resolution (kHz) point-on-wave data (transient)
and triggered based on configured settings. Data points shall
include:
 Time stamp
 Phase-to-ground voltage for each phase
 Bus frequency (as measured/calculated by the recording
device)
 Each phase current and residual or neutral current
 Calculated active and reactive power output
 If applicable, dynamic reactive device voltage,
frequency, current, and power output
 Applicable binary status
IBR unit autonomous functions parameter settings 148
Sequence of events
recording (SER) data
(tabular log file, time tag
shall have an accuracy of one
millisecond or less)

Measurement/data points (as applicable)
SER devices should be sized to capture and store hundreds or
thousands of event records and logs. SER event records can be
triggered for many different reasons but at minimum, shall
include the following:
 Event date/time stamp (synchronized to common
reference, e.g., Coordinated Universal Time [UTC])
 Event type (status changes, synchronization status,
configuration change, etc.)
 Sequence number (for potential overwriting)
Unit functional settings
Provision data type
Table 19—Measurement data—type, points, sampling rate, retention and duration (continued)
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
Input: ≥ 960
samples per s
output: ≥ 60
times
(records) per
s,
continuous149
Many kHz,
triggered
A DDR shall capture the specified plant-level data continuously
at the point of measurement. This data can be used for multiple
purposes including event analysis and disturbance-based model
verification. Data points shall include:
 Time stamp
 Bus voltage phasor (phase quantities and positivesequence)
 Bus frequency
 Current phasor (phase quantities and positive-sequence)
 Calculated active and reactive power output
For grid BPS faults/events which trigger ride-through operation
of an IBR unit or cause it to trip, the following information shall
be recorded at IBR units for analysis:
 All major and minor fault codes
 All fault and alarm status words
 Change of operating mode
 High- and low-voltage ride-through
 High- and low-frequency ride-through
 PLL loss of synchronism
 DC current and voltage
 AC phase currents and voltage
 Pulse width modulation index (if applicable)
 Control system command values, reference values, and
feedback signals
Plant-level Pst and Plt using a flicker meter that is compliant
with IEC 61000-4-15 and IEC 61000-4-30
Dynamic disturbance
recorder (DDR) data
(COMTRADE format and
tabular log file)
Inverter fault codes and
dynamic recordings (CSV
file and tabular log file)
Power quality—flicker
(PQDIF format)
90 days
90 days
1 year
Retention
NA
5-s data,
(split
between prefault and
post-fault
data needs to
be mutually
agreed upon
with the TS
owner/TS
operator)
NA 149
Duration
IEC 61000-4-30
Stated by IBR
owner
Subclause 4.4,
Table 2
Measurement (as
applicable)
149
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A DDR with continuous data recording and storage capability is required. However, if the TS owner allows a DDR which records based on triggers then triggered records shall be at least of 3 min. The
record triggers (i.e., frequency, voltage etc.) shall be based on mutual agreement between the TS owner and the IBR owner.
10 min
Recording
rate
Provision data type
Measurement/data points (as applicable)
Table 19—Measurement data—type, points, sampling rate, retention and duration (continued)
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
150
NA
Plant-level RVC (DeltaV/V) using a PQ meter that is compliant
with IEC 61000-4-30 (IEC RMS value measured by one cycle,
updated every half cycle)
Plant level, both voltage and current harmonics as applicable
(total distortion and individual harmonics up to order 50).
Unless required by the TS owner, very short-term harmonics
measurements are optional.
Plant level, both voltage and current harmonics as applicable
(total distortion and individual harmonics up to order 50).
Plant level, both voltage and current harmonics as applicable
(total distortion and individual harmonics up to order 50).
Power quality—RVC
(PQDIF format)
Power quality—Very shortterm harmonics
(COMTRADE or PQDIF
format)
Power quality—short-term
harmonics (COMTRADE or
PQDIF format)
Power quality—long-term
harmonics (COMTRADE or
PQDIF format)
1 year
90 days
10 days
90 days
Retention
NA
NA
NA
NA
Duration
IEC 61000-4-7 and
IEC 61000-4-30
IEC 61000-4-7 and
IEC 61000-4-30
IEC 61000-4-7 and
IEC 61000-4-30
IEC 61000-4-30 150
Measurement (as
applicable)
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The rapid voltage change algorithm should satisfy the requirements specified in IEC 61000-4-30:2015/AMD1:2021 or later.
(per IEEE
Std 519)
95 weekly
percentile
10 min
3s
Recording
rate
Measurement/data points (as applicable)
Provision data type
Table 19—Measurement data—type, points, sampling rate, retention and duration (continued)
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
12. Test and verification requirements
12.1 Introduction
This clause specifies the test and verification requirements and methods applicable to each IBR
interconnection and interoperability requirement specified in Clause 4 through Clause 11. This clause further
specifies at which stages in the interconnection process testing and verification shall be required. 151 The
applicable test and verification methods from this clause are required for all IBRs. The results of these test
and verification methods shall be formally documented.
12.2 Definitions of verification methods
12.2.1 General
All IBR interconnection and interoperability requirements of this standard shall be verified by a combination
of the following methods as specified in this clause: type tests, IBR evaluations, commissioning tests, and
operational evaluation. 152
Details of which verification method(s) apply to which requirements are specified in Table 20. These
verification methods may apply to IBR plants, IBR units, and/or supplemental IBR devices used to meet the
respective requirements.
12.2.2 Type tests
A type test 153 may be performed on one device or a combination of devices. Type tests shall be performed on
IBR units as well as supplemental IBR devices that are used to meet the requirement of this standard as
specified in Table 20. 154
NOTE—Type tests are rarely, if ever, applied to entire IBR plants. The IBR unit type test results may not be directly used
to verify ride-through capability requirements; however, they may be needed because the type test results may be used
to develop an IBR plant–level model which may be used in the IBR plant design evaluation to verify requirements.
In cases where a supplemental IBR device is used to meet a requirement of this standard as specified in
Table 20, the type test for such device in combination with other information on this device shall provide
sufficient information to render possible verification during the design evaluation (see 12.2.3) of that specific
requirement and any other requirement(s) for which conformance of the IBR plant to this standard may be
impacted by that supplemental IBR device. The details of type tests are not provided in this standard, and may
be provided by other standards, including by referencing existing standards as appropriate.
This standard specifies what verification methods shall be used and when these apply in the interconnection process. It is expected
that IEEE P2800.1 and IEEE P2800.2 will specify how these verification methods will be implemented, including the specification of
test and evaluation procedures along with their pass/fail criteria. The applicability of IEEE Std 2800, IEEE P2800.1, or IEEE P2800.2
are determined by the AGIR for the location (IEEE P2800.1 and IEEE P2800.2 are presently under development and are designated
IEEE P2800.1 and IEEE P2800.2 prior to approval).
152
Development of dedicated type test procedures complementing this standard is recommended. Existing type test procedures, such as
IEEE Std 1547.1-2020 [B51], IEC 61400-21-1 [B37], FGW TR3 [B24], FGW TR4 [B25], FGW TR8 [B26], IEC 62927 [B41], IEEE
Std 115 [B49], IEC 60034-4-1 [B31], or IEC TS 60034-16-3 [B43], may or may not be appropriate to verify compliance with this
standard. Certification of equipment, for example, under UL 1741 SA [B108], UL 1741 SB [B109], or UL 1741 CRD PCS [B107] is
outside the scope of this standard.
153
Refer to 3.1 for the definition of type test.
154
Almost all of the performance requirements of this standard apply at the POM or POI, and thus type tests will not be able to fully
verify compliance with this standard, but will serve to provide information useful to making this determination based on the design
evaluation. Such information may include verified IBR unit and supplemental IBR device models as specified in Clause 10.
151
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
IBR units and supplemental IBR devices that are too large or have power ratings too high to be practically
type tested may demonstrate conformance through other means. 155
Type tests shall be performed on a representative IBR unit or subsystem 156 that represents the behavior of the
IBR, either in the factory, at a testing laboratory or on equipment in the field. Type test procedures shall be
designed to comprehensively verify relevant aspects of performance under simulated conditions (electrical
and mechanical). Type test results from an IBR unit within a product family of the same design, including
hardware and software, shall be allowed as representative of other IBR units within the same product family
with different power ratings provided the hardware and software designs are appropriately scaled but not
otherwise different between models.
While many of the requirements that are verified or partially verified through type testing apply at the POM,
type testing typically is applied at the POC of the device under test. Thus, type tests and subsequent
verification steps that use type test results as input shall take into account differences in conditions between
POC and POM, and shall consider the aggregate behavior of the multi IBR unit and supplemental IBR device
differences and responses.
For systems in the field, replacement of IBR plant components with substitutive components that have been
verified compliant with this standard shall be allowed and not invalidate previous type tests. Field
demonstration of compliance shall be agreed with the TS operator.
12.2.3 Design evaluation
The design evaluation (desk study) is an engineering evaluation during the interconnection and plant
commissioning process to verify that the IBR plant, as designed, or the IBR unit(s), as applicable, meet the
interconnection and interoperability requirements of this standard. The IBR plant design evaluation may be
performed by the IBR owner, TS operator, TS owner, third-party consultants, and/or jointly by these parties.
The design evaluation often includes modeling and simulation of the IBR plant, its IBR unit(s), and
supplemental IBR device(s), and the interactions with the TS. This evaluation does not include testing.
However, reports derived from test results may be consulted in the design evaluation, and the model
verification may be informed by the results from type tests if available. The design evaluation may also
determine other verification steps that may be required, such as commissioning testing or postcommissioning monitoring. The details of interconnection review process vary among TS owners/TS
operators and may be dependent on regional regulatory requirements.
In cases where a supplemental IBR device may be used to provide IBR plant or IBR unit(s) conformance with
a subset of requirements of this standard, the design evaluation shall be specific to such requirement(s) along
with any other IBR plant or IBR unit requirement(s) for which conformance to this standard may be impacted
by that supplemental IBR device.
12.2.4 As-built installation evaluation
The IBR plant as-built installation evaluation (on-site) is an evaluation at the time of commissioning to verify
that IBR units, the collector system, supplemental IBR device(s), and protective functions forming an IBR
plant as delivered and installed meets or exceeds the design as defined in the IBR plant design evaluation.
For example, VSC-HVDC units, FACTS units, very large power electronic converters.
An example of a subsystem that represents the behavior of the IBR can be a solar inverter or generator-inverter combination in the
case of type IV wind turbine. The subsystem selected may be dependent on the type test performed and shall be the components used
in the IBR product. The subsystem selected shall be in agreement between the IBR manufacturer and verification entity.
155
156
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
12.2.5 Commissioning tests
The IBR commissioning tests are verifications conducted in the field on one or more IBR unit(s),
supplemental IBR devices, and/or an IBR plant to verify that the IBR plant as designed, delivered, and
installed meets the interconnection and interoperability requirements of this standard.
All commissioning tests shall be performed based on written test procedures. These test procedures shall
follow good engineering practice and shall be subject to approval by the TS operator, as appropriate for the
requirement specified in Table 20. Commissioning tests may include, as applicable, operability and
functional performance tests.
12.2.6 Post-commissioning model validation
A post-commissioning model validation confirms and calibrates that the models supplied during the design
evaluation accurately represent the IBR plant as installed and configured in the field, as the design,
equipment, and control settings may have changed since the initial system modeling was performed. The
outcome of this phase is a design of record consisting of final IBR plant specifications and models as
described in Clause 10 to be used by the TS operator and the TS owner as representative of the state of the
IBR plant.
12.2.7 Post-commissioning monitoring
Post-commissioning monitoring consists of evaluating IBR plant’s performance in the field during operation,
especially following TS events where the POM voltage and/or frequency deviate from the normal operating
region. Post-commissioning monitoring verifies that the IBR plant continues to meet the requirements of this
standard over its operational lifetime. 157
12.2.8 Periodic tests
Periodic tests re-confirm the performance of the IBR plant at prescribed points in time after it has been
commissioned and put into operation.
12.2.9 Periodic verification
Periodic verification takes place following any substantial changes, 158 as defined by the TS owner or the TS
operator, to the IBR plant and confirms that the as-modified IBR plant continues to meet the requirements of
this standard.
Once the IBR plant is operational, modifications to controls or hardware that change the response of the IBR
plant or IBR units as defined within this standard shall be mutually agreed upon between the TS operator/TS
owner and the IBR owner.
157
In North America, reliability standards of the North American Electric Reliability Corporation (NERC) may apply, including, but
not limited to, MOD-025-2 [B92], MOD-026-1 [B93], MOD-027-1 [B94], and MOD-031-1 [B95].
158
These may include, but are not necessarily limited to:

Functional software or firmware changes have been made on the IBR plant that affect the verified plant performance.

Any hardware component of the IBR plant has been modified in the field or has been replaced or repaired with parts that are
not substitutive components compliant with this standard.

Protection settings have been changed after factory testing.

Protection functions have been adjusted after the initial commissioning process.
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
12.3 Conformance verification framework
12.3.1 General
Table 20 specifies the kind and sequence of verification methods that shall be used to confirm compliance of
an IBR plant, including IBR units and any supplemental IBR devices, with the requirements of this standard.
Alternative means to verification may be mutually agreed upon between the TS operator/TS owner and the
IBR owner.
Each row in the table lists a requirement of this standard along with the reference point of applicability of
that specific requirement in the second column. The remaining column entries specify the required methods
of verification as defined in 12.2. For a new IBR plant, a requirement shall be considered verified when all
the specified verification methods through post-commissioning model validation have been satisfactorily
completed.
Some verification methods may or may not be required depending on the result of the IBR plant design
evaluation or depending on agreement with the TS operator/TS owner. Such methods are listed as “D”
(depends) in Table 20.
Some clauses in this standard are not listed in Table 20 because they do not contain requirements. Other
clauses that do contain requirements are not listed in Table 20 because they do not require dedicated
verification; instead they inform other requirements of the standard.
Table 20 provides minimum verification requirements; the TS operator/TS owner shall not be limited from
requiring supplemental commissioning testing and verification.
12.3.2 Verification methods matrix
Table 20 specifies the verification method(s) that shall apply for each applicable requirement of this standard.
101
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As-built
installation
evaluation
R
R
R
R
NR
NR
R
NR
D
D
R
NR
POM
POM
POM
POM
POM and
POC
POM
POM
POM
R
R
R
R
R
NR
POM
R
R
R
NR
R
NR
IBR developer
/TS owner/
TS operatora
R
R
R
R
R
R
R
R
R
R
R
NR
IBR developer
/TS owner/
TS operatora
NR
R
NR
NR
R
D
R
R
R
R
R
NR
IBR developer/
TS owner/
TS operatora
NR
R
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
NR
R
NR
R
NR
R
R
R
R
R
R
NR
IBR operator/
TS owner/
TS operatora
Periodic
verification
D
D
NR
D
R
D
D
D
D
D
D
NR
NR
NR
NR
NR
NR
NR
D
D
D
D
D
NR
IBR operator/ IBR operator/
TS owner/
TS owner/
TS operatora TS operatora
PostPostcommissioning commissioning Periodic tests
model validation
monitoring
Responsible entity
Commissioning
tests
IBR developer/
IBR operator/
TS owner/
TS operatora
Clause 4 General interconnection technical specifications and performance requirements
IBR unit or
supplemental IBR
device manufacturera
POM
POM
(default)
POC and
POM
RPA where
requirement
applies
Design evaluation
(including
modeling for most
requirements)
IBR plant-level verifications (at the RPA)
159
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102
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In cases where a supplemental IBR device is used for the IBR plant to meet a requirement of this standard as specified in Table 20, the type test for such device provides sufficient information to render possible verification
during the design evaluation (see 12.2.3) of that specific requirement and any other requirement(s) for which conformance of the IBR plant to this standard may be impacted by that supplemental IBR device.
4.5 Operational measurement
and communication capability
4.6 Control capability
requirements
4.6.1 Execution of mode or
parameter changes
4.6.2 Ramping for control
parameter change
4.7 Prioritization of IBR
responses
4.8 Isolation device
4.9 Inadvertent energization of
the TS
4.10 Enter service
4.11 Interconnection integrity
4.12 Integration with TS
grounding
4.4 Measurement accuracy
4.2 Reference points of
applicability (RPA)
Requirement
Type tests 159
IBR unit-level tests
(at the POC)
Table 20 —Verification methods matrixa
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
IBR developer
/TS owner/
TS operatora
As-built
installation
evaluation
IBR developer/
TS owner/
TS operatora
IBR developer/
IBR operator/
TS owner/
TS operatora
R
R
POM
POM
R
R 162
R
R
R
R
R
R
R
R
R
R
R
R
R
Refer to line entries for 4.10
NR
NR
NR
R
R
R
R
R
R
R
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
IBR operator/ IBR operator/
TS owner/
TS owner/
TS operatora TS operatora
Periodic
verification
160
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103
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In cases where a supplemental IBR device is used for the IBR plant to meet a requirement of this standard as specified in Table 20, the type test for such device provides sufficient information to render possible verification
during the design evaluation (see 12.2.3) of that specific requirement and any other requirement(s) for which conformance of the IBR plant to this standard may be impacted by that supplemental IBR device.
161
PFR is typically carried out by plant-level controls. Therefore, as long as the IBR unit provides the ability to respond to power commands which are required for other capability, there is no other type test required for PFR
at the IBR unit level and can be performed at the IBR plant level.
162
If FFR is activated under direct control from the IBR unit, then this test has to be performed at the IBR unit level. Otherwise, it can be performed at the IBR plant level.
163
Requirements in 7.2.2.3 apply at POC.
164
Requirements in 7.2.2.1, 7.2.2.2, 7.2.2.4, and 7.2.2.6 apply at POM. The IBR unit type test results may not be directly used to verify ride-through capability requirements; however, they may be needed because the type test
results may be used to develop an IBR plant–level model which may be used in the IBR plant design evaluation to verify requirements.
R
R
R
Clause 7 Response to TS abnormal conditions
R
POC 163 and
POM 164
R
R
IBR operator/
TS owner/
TS operatora
PostPostcommissioning commissioning Periodic tests
model validation
monitoring
Responsible entity
Commissioning
tests
Clause 6 Active-power—frequency response requirements
R
R
NR 161
7.2.2 Voltage disturbance ridethrough requirements
7.2.3 Transient overvoltage ridethrough requirements
7.3.2 Frequency disturbance
ride-through requirements
7.4 Return to service after IBR
plant trip
D
POM
POC and
POM
POC and
POM
R
POM
POM
IBR developer
/TS owner/
TS operatora
Design evaluation
(including
modeling for most
requirements)
IBR plant-level verifications (at the RPA)
Clause 5 Reactive power—voltage control requirements within the continuous operation region
IBR unit or
supplemental IBR
device manufacturera
6.1 Primary frequency response
(PFR)
6.2 Fast frequency response
(FFR)
5.1 Reactive power capability
5.2 Voltage and reactive power
control modes
Requirement
RPA at which
requirement
applies
Type
tests 160
IBR unit-level tests
(at the POC)
Table 20 —Verification methods matrix (continued)a
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
165
R 165
D
R
D
POM
POM
POM
POM
POM
R
R
R
R
R
R
Clause 9 Protection
R
R
D
R
NR
R
R
R
R
R
D
R
NR
NR
D
R
R
R
IBR developer/
TS owner/
TS operatora
NR
R
R
R
R
R
NR
NR
D
D
D
D
IBR developer/
IBR operator/
TS owner/
TS operatora
R
R
R
R
R
R
R
R
D
R
R
R
IBR operator/
TS owner/
TS operatora
Periodic
verification
D
D
D
D
D
D
NR
NR
D
N/A
N/A
D
D
D
D
D
D
D
NR
NR
D
D
D
D
IBR operator/ IBR operator/
TS owner/
TS owner/
TS operatora TS operatora
PostPostcommissioning commissioning Periodic tests
model validation
monitoring
Responsible entity
Commissioning
tests
104
Copyright © 2022 IEEE. All rights reserved.
R
D
R
R
R
R
R
R
D
R
NR
R
IBR developer
/TS owner/
TS operatora
As-built
installation
evaluation
Clause 8 Power quality
IBR developer
/TS owner/
TS operatora
Design evaluation
(including
modeling for most
requirements)
IBR plant-level verifications (at the RPA)
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NR
D
D
D
D
D
NR
POM
POC and
POM
POC and
POM
POC and
POM
POC and
POM
POC and
POM
NR
IBR unit or
supplemental IBR
device manufacturera
POM
Required only for IBR unit rated up to 1.0 MW.
9.6 Interconnection system
protection
9.5 Unintentional islanding
protection
9.4 AC overcurrent protection
9.3 Voltage protection
9.2 Rate of change of frequency
(ROCOF) protection
9.1 Frequency protection
8.1.2 Rapid voltage changes
(RVC)
8.1.3 Flicker
8.2.1 Harmonic current
distortion
8.2.2 Harmonic voltage
distortion
8.3.1 Limitation of cumulative
instantaneous overvoltage
8.3.2 Limitation of overvoltage
over one fundamental frequency
period
Requirement
RPA at which
requirement
applies
Type
tests 160
IBR unit-level tests
(at the POC)
Table 20 —Verification methods matrix (continued)a
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
11 Measurement data for
performance monitoring and
validation
Verification step is not required.
R
NR
IBR developer/
TS owner/
TS operatora
R
R
R
NR
R
IBR developer/
IBR operator/
TS owner/
TS operatora
R
R
IBR operator/
TS owner/
TS operatora
D
D
D
D
Not applicable.
105
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Dependent on IBR evaluation and/or agreement with TS operator/TS owner.
N/A
NOTE—The scope of a required verification method may vary based on the IBR design and may be mutually agreed upon between the TS operator/TS owner and IBR owner. For test and evaluation procedures along
with their pass/fail criteria refer to applicable standards.
Verification step is required.
Periodic
verification
IBR operator/ IBR operator/
TS owner/
TS owner/
TS operatora TS operatora
PostPostcommissioning commissioning Periodic tests
model validation
monitoring
Responsible entity
Commissioning
tests
NOTE—This standard does not prohibit the TS operator/TS owner from requiring additional verification when mutually agreed upon between the TS operator/TS owner and IBR owner.
D
R
IBR developer
/TS owner/
TS operatora
Clause 10 Modeling Data
IBR developer
/TS owner/
TS operatora
As-built
installation
evaluation
IBR plant-level verifications (at the RPA)
Clause 11 Measurement data for performance monitoring and validation
NR
IBR unit or
supplemental IBR
device manufacturera
Design evaluation
(including
modeling for most
requirements)
D
R
NR
Abbreviations for Table 20:
POC and
POM
10 Modeling data
a
POC and
POM
Requirement
RPA at which
requirement
applies
Type
tests 160
IBR unit-level tests
(at the POC)
Table 20 —Verification methods matrix (continued)a
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with Associated Transmission Electric Power Systems
IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Annex A
(informative)
Bibliography
Bibliographical references are resources that provide additional or helpful material but do not need to be
understood or used to implement this standard. Reference to these resources is made for informational use
only.
[B1]
Abad, G., Lopez, J., Rodriguez, M., Marroyo, L., and Iwanski, G., Doubly-Fed Induction Machine:
Modeling and Control for Wind Energy Generation, Wiley/IEEE Press, 2011.
[B2]
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Systems, Wiley/IEEE Press, 1999.
[B3]
Anderson, P. M., and Farmer, R. G., Series Compensation of Power Systems, PBLSH! Inc., 1996.
[B4]
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[B5]
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168
CIGRE publications are available from the Council on Large Electric Systems (https://www.e-cigre.org/).
166
167
106
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
[B18] EPRI, Common File Format for Distributed Energy Resources Settings Exchange and Storage, 10
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[B34] IEC 60255-181, Measuring relays and protection equipment—Part 181: Functional requirements
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[B35]
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EPRI publications are available from the Electric Power Research Institute (https://www.epri.com).
IEC publications are available from the International Electrotechnical Commission (https://www.iec.ch) and the American National
Standards Institute (https://www.ansi.org/).
169
170
107
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
[B36] IEC 61400-3-1:2019, Wind energy generation systems—Part 3-1: Design requirements for fixed
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[B37] IEC 61400-21-1, Wind turbines—Part 21: Measurement and assessment of electrical
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[B39]
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[B40]
IEC 62443-All parts, Security for industrial automation and control systems. 172
[B41] IEC 62927, Voltage sourced converter (VSC) valves for static synchronous compensator
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[B42] IEC TR 61000-3-6:2008, Electromagnetic compatibility (EMC)—Part 3-6: Limits—Assessment of
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[B43] IEC TS 60034-16-3, Rotating electrical machines—Part 16: Excitation systems for synchronous
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[B47] IEEE Power & Energy Society, Technical Report PES-TR78, Modification of commercial fault
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[B48] IEEE Power & Energy Society, Technical Report PES-TR81, Protection Challenges and Practices
for Interconnecting Inverter Based Resources to Utility Transmission Systems, Jul. 2020.
[B49] IEEE Std 115™, IEEE Guide for Test Procedures for Synchronous Machines Including Acceptance
and Performance Testing and Parameter Determination for Dynamic Analysis.
[B50] IEEE Std 1547™, IEEE Standard for Interconnection and Interoperability of Distributed Energy
Resources with Associated Electric Power Systems Interfaces.
[B51] IEEE Std 1547.1™, IEEE Standard Conformance Test Procedures for Equipment Interconnecting
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[B52]
IEEE Std 1686™, IEEE Standard for Intelligent Electronic Devices Cyber Security Capabilities.
[B53] IEEE Std 1815™, IEEE Standard for Electric Power Systems Communications-Distributed
Network Protocol (DNP3).
IEC 62351 series of standards provide guidelines for managing cybersecurity of communication protocols including IEC 61850
(IEEE Std 1815, DNP3), IEC 60870-6 (ICCP, TASE.2), and IEC 61850 (GOOSE). The following standards may be found particularly
relevant: IEC 62351-3: Data and Communication Security—Profiles Including TCP/IP; IEC 62351-4: Data and Communication
Security—Profiles Including MMS and Similar Payloads; IEC 62351-5: Data and Communication Security—Security for IEC 60870-5
and Derivatives (i.e., DNP 3.0); and IEC 62351-6: Data and Communication Security—Security for IEC 61850 Peer-to-Peer Profiles.
172
ISA/IEC 62443 series of security standards are a combination of multiple standards developed for industrial automation and control
systems and address the unique operational needs of digital systems well. Part 3-2: 2020—Security risk assessment for system design,
Part 4-1: 2018—Secure product development lifecycle requirements; and Part 4-2: 2019—Technical security requirements for IACS
components may provide useful guidance in the context of this standard.
173
Numbers preceded by P are IEEE authorized standards projects that were not approved by the IEEE-SA Standards Board at the time
this publication went to press. For information about obtaining drafts, contact the IEEE.
171
108
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
[B54] IEEE Std 2030™, IEEE Guide for Smart Grid Interoperability of Energy Technology and
Information Technology Operation with the Electric Power System (EPS), End-Use Applications, and Loads.
[B55]
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[B61] IEEE Std C50.13™, IEEE Standard for Cylindrical-Rotor 50 Hz and 60 Hz Synchronous Generators
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technology) applied to process control systems in the electric energy industry, except nuclear facilities. The guideline provides a
comprehensive security requirement for commonly used devices and systems for power generation, delivery, and utilization.
Standards handle the specifics of industrial control systems and their operational environments while referring to ISO/IEC 27002:2013
for the IT-specific implementation details.
174
109
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
[B72] NERC, 1,200 MW Fault Induced Solar Photovoltaic Resource Interruption Disturbance Report.
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NERC Standard CIP-002, Cyber Security—BES Cyber System Categorization.
[B79]
NERC Standard CIP-003, Cyber Security—Security Management Controls.
[B80]
NERC Standard CIP-004, Cyber Security—Personnel & Training.
[B81]
NERC Standard CIP-005, Cyber Security—Electronic Security Perimeters.
[B82]
NERC Standard CIP-006, Cyber Security—Physical Security Management.
[B83]
NERC Standard CIP-007, Cyber Security—System Security Management.
[B84]
NERC Standard CIP-008, Cyber Security—Incident Reporting and Response Planning.
[B85]
NERC Standard CIP-009, Cyber Security—Recovery Plans for BES Cyber Systems.
[B86] NERC Standard CIP-010, Cyber Security—Configuration Change Management and Vulnerability
Assessment.
[B87]
NERC Standard CIP-011, Cyber Security—Information Protection.
[B88]
NERC Standard CIP-013, Cyber Security—Supply Chain Risk Management.
[B89]
NERC Standard CIP-014, Cyber Security—Physical Security.
[B90]
NERC Standard FAC-001-3, Facility Interconnection Requirements.
[B91]
NERC Standard FAC-002-2, Facility Interconnection Studies.
[B92] NERC Standard MOD-025-2, Verification and Data Reporting of Generator Real and Reactive
Power Capability and Synchronous Condenser Reactive Power Capability.
[B93]
NERC Standard MOD-026-1, Verification of Models.
[B94]
NERC Standard MOD-027-1, Data for Generators.
[B95]
NERC Standard MOD-031-1, Demand and Energy Data.
[B96]
NERC Standard PRC-002-2, Disturbance Monitoring and Reporting Requirements.
[B97]
NERC Standard PRC-024-2, Generator Frequency and Voltage Protective Relay Settings.
[B98]
NERC Standard TPL-001-4, Transmission System Planning Performance Requirements.
[B99]
NERC Standard VAR-002-4.1, Generator Operation for Maintaining Network Voltage Schedules.
175
NERC publications are available from the North American Electric Reliability Corporation (https: www.nerc.com/).
110
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IEEE Std 2800-2022
IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
[B100] NISTIR 7628 Rev. 1, Guidelines for Smart Grid Cyber Security, Volume 1—Smart Grid
Cybersecurity Strategy, Architecture, and High-Level Requirements. 176, 177
[B101] Pourbeik, P., Sullivan, D. J., Boström, A., Sanchez-Gasca, J., Kazachkov, Y., Kowalski, J., Salazar,
A., Meyer, A., Lau, R., Davies, D., and Allen, E., “Generic Model Structures for Simulating Static Var
Systems in Power System Studies—A WECC Task Force Effort,” IEEE Transactions on PWRS, vol. 27, no.
3, 1618–1627, Aug. 2012.
[B102] PSCAD Model Requirements Rev. 9, Winnipeg, MB, Canada: Electranix.
[B103] Ramasubramanian, D., et al., “Positive Sequence Voltage Source Converter Mathematical Model
for Use in Low Short Circuit Systems,” IET Generation, Transmission & Distribution, vol. 14, no. 1, pp. 87–
97, Jan 2020.
[B104] Sandia Report, “Impact of Inverter-Based Resource Negative-Sequence Current Injection on
Transmission System Protection,” SAND2020-0265, Jan. 2020.
[B105] Schweitzer, E., and Hou, D., “Filtering for protective relaying,” Proceedings of the 19th Annual
Western Protective Relaying Conference, Spokane, WA, 20–22 Oct. 1992.
[B106] SSCI-SSR Screening and Modelling requirements Rev. 0, Winnipeg, MB, Canada: Electranix.
[B107] UL 1741 CRD PCS, Inverters, Converters, Controllers and Interconnection System Equipment for
Use With Distributed Energy Resources, Sep. 2019. 178
[B108] UL 1741 SA, Supplement SA to Inverters, Converters, Controllers and Interconnection System
Equipment for Use With Distributed Energy Resources, Sep. 2016.
[B109] UL 1741 SB, Supplement SB to Inverters, Converters, Controllers and Interconnection System
Equipment for Use With Distributed Energy Resources, Sep. 2021.
[B110] VDE-AR-N 4120:2018-11, Technical requirements for the connection and operation of customer
installations to the high voltage network (TAR high voltage). 179
[B111] VDE-AR-N 4130:2018-11, Technical connection rules for extra high-voltage. 180
[B112] Wang, X., and Blaabjerg, F., “Harmonic Stability in Power Electronic-Based Power Systems:
Concept, Modeling, and Analysis,” IEEE Transactions on Smart Grid, vol. 10, no. 3, pp. 2858–2870, 2018.
[B113] Weise, B., “Impact of K-factor and Active Current Reduction During Fault-Ride-Through of
Generating Units Connected via Voltage-Sourced Converters on Power System Stability,” IET Renewable
Power Generation, vol. 9, no. 1, pp. 25–36, 1 Jan. 2015. doi: 10.1049/iet-rpg.2014.0116.
[B114] Zhang, Y., Huang, Y., Schmall, J., Conto, J., Billo, J., and Rehman, E., “Evaluating system strength
for large-scale wind plant integration,” 2014 IEEE PES General Meeting, National Harbor, MD, pp. 1–5,
27–31 Jul. 2014.
176
NISTIR 7628 rev.1 discusses high-level cybersecurity requirements for smart grid. Although its coverage for behind-the-meter
resources is weak, for the transmission-connected assets and utility systems, it provides well-organized sets of security requirements.
Chapter 3, High-Level Security Requirements and Chapter 4, Cryptography and Key Management may be found relevant to IBR
interconnection and management.
177
NIST publications are available from the National Institute of Standards and Technology (https://www.nist.gov/).
178
UL publications are available from Underwriters Laboratories (https://www.ul.com/).
179
Available online: https://www.vde.com/en/fnn/topics/technical-connection-rules/tar-for-high-voltage.
180
Available online: https://www.vde.com/en/fnn/topics/technical-connection-rules/tcr-extra-high-voltage.
111
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IEEE Standard for Interconnection and Interoperability of Inverter-Based Resources (IBRs) Interconnecting with
Associated Transmission Electric Power Systems
Annex B
(informative)
Inverter-based resource (IBR) interconnection examples
This informative annex provides various examples of IBR interconnections.
B.1 AC interconnection examples
Figure 1 defines terms for ac-connected IBRs. Figure B.1 shows the basic ac interconnections via a short and
long interconnection system (IBR tie line) between an IBR plant and the transmission system (TS).
Points A and B indicate the terminals of the IBR interconnection system. In many ac interconnection cases,
point A may refer to as the point of measurement (POM) and point B as the point of interconnection (POI).
Figure B.1—Basic ac interconnections via short and long interconnection system
Figure B.2 shows a special example of an offshore IBR plant that includes a dedicated MV/HV transformer
located offshore that steps up the collector system voltage to the voltage of an ac export cable which connects
to the main IBR transformer(s) located onshore.
NOTE—Refer to the exception in 5.1 for the minimum reactive power capability requirements for an ac-connected
offshore IBR plant.
IBR
Unit
Default RPA: point
of measurement (POM)
MV/HV
IBR
Unit
…
IBR
Unit
interconnection
system
High Voltage AC Export cable
(POC)
Shunt
Reactor
Shunt
Reactor
transmission system
(TS)
main IBR
transformer(s)
IBR tie line
offshore
IBR plant
One alternate RPA: point of
interconnection (POI)
Figure B.2—Offshore IBR plant with high-voltage ac export cable
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Associated Transmission Electric Power Systems
Figure B.3 shows various interconnection configurations including:

A single IBR plant interconnected to the transmission system (TS) via ac interconnection system. In
this example, the IBR plant and ac interconnection system both are owned by the same entity.

A single IBR plant consisting of IBR units by several different manufacturers interconnected to the
TS via ac interconnection system. In this example, the ac interconnection system is owned by an
entity different from IBR owner.

Several IBR plants interconnected to the TS via ac interconnection system. In this example, the ac
interconnection system is owned by an entity different from IBR owners.
The last example also shows IBR plants connected at various locations along the ac interconnection system.
This configuration can occur when several IBR plants are developed at different times and interconnect to an
independent ac transmission line. Such a configuration may result in IBR plant coordination challenges.
Points A and B indicate the terminals of the ac interconnection system. Regardless of ownership of IBR
plant(s) and ac interconnection system, the default reference point of applicability (RPA) for each IBR plant
is point of measurement, i.e., point A.
Figure B.3: AC interconnections examples
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Associated Transmission Electric Power Systems
B.2 DC interconnection examples
Figure 2 defines terms for dc-connected isolated IBRs. Figure B.4 shows various configurations for dcconnected isolated IBRs. In these configurations, each isolated IBR and voltage source converter highvoltage direct current (VSC-HVDC) transmission line may be owned by different entities. Examples include:

An isolated IBR interconnected to the TS via VSC-HVDC transmission line

An isolated IBR consisting of IBR units by several different manufacturers interconnected to the TS
via VSC-HVDC transmission line

Several isolated IBRs interconnected to the TS via VSC-HVDC transmission line
This standard applies to isolated IBRs interconnected via a dedicated VSC-HVDC transmission line even
though isolated IBR(s) and the VSC-HVDC transmission line may be owned by various entities. In these
configurations, point A is an arbitrary point within the combined facility consisting of isolated IBR(s) and
the VSC-HVDC transmission line. The point of measurement (POM) is located at point B (ac side of the dcto-ac converting station and isolation transformer, if present). In cases where an ac interconnection system
connects the POM to the TS, the point of interconnection (POI) is located near the TS.
Figure B.4: DC interconnection examples
In the last example in Figure B.4, although there are three separate isolated IBRs connected by one VSCHVDC transmission line, this standard considers this combined facility to be a single IBR plant with its POM
and POI located on the side where the dc-to-ac converting station connects to the TS. The default RPA is the
POM, but the TS owner may move the RPA to the POI. There may be a significant need for coordination for
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Associated Transmission Electric Power Systems
the three isolated IBR owners and the VSC-HVDC project developer to help ensure performance of the
combined facility meets the requirements specified in this standard at the designated RPA.
NOTE 1—This standard applies to isolated inverter-based resources (IBRs) interconnected via dedicated voltage source
converter (VSC) high-voltage direct current (HVDC) transmission facilities.
NOTE 2—This standard does not apply to line-commutated HVDC interconnections.
NOTE 3—This standard is not intended to apply to VSC-HVDC connecting two ac interconnections with each other.
NOTE 4—This standard is not intended to specify requirements for VSC-HVDC that connect two buses within a
meshed/networked synchronous ac system.
NOTE 5—The requirements for cases where IBR are integrated with a multi-terminal VSC HVDC transmission schemes
may be specified by the TS owner.
NOTE 6—The requirements for cases where IBR and non-IBR are connected via VSC-HVDC, i.e., hybrid resource
facilities, may be specified by the TS owner.
B.3 Complex IBR plant examples
Figure B.5 and Figure B.6 show examples for hybrid IBR plants. The hybrid IBR plant is defined in 3.1 and
repeated here for convenience. The hybrid IBR plant is a hybrid plant that is composed of only inverter-based
resources and/or energy storage systems (ESSs).
NOTE 1—A common hybrid IBR plant combines renewable energy (solar photovoltaic [PV] or wind) and energy storage
systems.
NOTE 2—The requirements of this standard apply to both ac-coupled hybrid IBR plants (couples each form of generation
or storage at a common collection bus after it has been converted from dc to ac at each individual inverter) and dc-coupled
hybrid IBR plants (couples both sources at a dc bus that is tied to the grid via a dc-ac inverter).
Figure B.5—Example hybrid IBR plant, ac-coupled
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Associated Transmission Electric Power Systems
Figure B.6—Example hybrid IBR plant, dc-coupled
Figure B.7 shows an example of a hybrid plant. The hybrid plant is defined in 3.1 and repeated here for
convenience. The hybrid plant is a generating or storage facility that is composed of multiple types of
resources or energy storage systems controlled and operated as a single resource behind a single point of
interconnection (POI).
NOTE 1—The resources in a hybrid plant may include conventional electric generating units (such as fossil fuel–driven
synchronous generators and hydro-electric generation) and inverter-based resources (such as wind, solar PV, and energy
storage systems). Examples for other equipment in a hybrid resource includes synchronous condensers and compensation
not part of the IBR plant(s).
NOTE 2—The requirements of this standard only apply to the IBR plant(s) in a hybrid plant. Other standards’
requirements may be applicable to the conventional generation resources.
NOTE 3—The generating or storage facilities may have a single main transformer with a common POM and POI to
facilitate operations as a single resource, but separate RPAs may be required for the IBR generating or storage facilities
and the conventional generating facilities to facilitate measurement of compliance to applicable standards.
Figure B.7—Example hybrid plant
Figure B.8, Figure B.9, and Figure B.10 show examples of co-located plants. The co-located plant is defined
in 3.1 and repeated here for convenience. The co-located plant is where two or more generation or storage
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Associated Transmission Electric Power Systems
resources that are operated and controlled as separate entities are connected behind a single point of
interconnection (POI).
NOTE 1—The resources of a co-located plant may require separate POMs behind the single POI.
NOTE 2—The requirements of this standard only apply to the co-located IBR plant(s). Other standards’ requirements
may be applicable to the co-located conventional generation resources and co-located non-IBR ESS.
Figure B.8—Example co-located plant, example 1
Figure B.9—Example co-located plant, example 2
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Associated Transmission Electric Power Systems
Figure B.10—Example co-located plant, example 3
Figure B.11 shows an example for an IBR plant with synchronous condenser as supplemental IBR device. As
defined in 3.1, the supplemental IBR device is any equipment within an IBR plant, which may or may not be
inverter-based, that is only used to obtain compliance with some or all of the interconnection requirements
of this standard.
NOTE 1—Examples include equipment such as capacitor banks, static synchronous compensators (STATCOMs),
harmonic filters, protective devices, and plant controllers, etc.
NOTE 2—In cases where synchronous condenser is used as a supplemental IBR device, refer to a general exemption in
1.4.
NOTE 3—Supplemental IBR devices may meet or exceed applicable equipment standards, as determined by an IBR
plant design evaluation.
Figure B.11—Example IBR plant with synchronous condenser as supplemental IBR device
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Associated Transmission Electric Power Systems
Annex C
(informative)
Inverter stability and system strength
C.1 Introduction to transmission-connected inverter-based resources (IBRs)
C.1.1 Control of transmission-connected inverter-based resources
In an IBR plant connected to the transmission system there may exist hundreds of individual inverters
connected to each other through a collector network (usually ≤ 66 kV). In a wind plant, usually, the number
of inverters equals the number of turbines, while in a solar plant, each inverter collects energy from hundreds
of individual photovoltaic (PV) panels. Therefore, IBR plants typically have three layers of controls that
operate on different time scales: a plant controller that executes high-level supervisory control including
coordination across the various controllable units within the plant (including reactive compensation if
applicable), and an inverter controller that typically contains two loops, a fast or “inner loop” control, and a
slower “outer loop.” Although control architectures and layers in an inverter-based plant are often
proprietary, the layers and functional loops of the various controls rarely change.
Figure C.1 shows the relationship between the plant and inverter controllers. The top diagram in Figure C.1
shows an IBR using a variable-frequency ac primary source, whereas the bottom diagram shows an IBR
using a dc primary source. (Type III wind turbine generators are a special case and are discussed separately
below.) In both cases, a single plant-level controller usually communicates with multiple inverter controllers.
Figure C.2 provides a block diagram of a conventional inverter controller. A “conventional inverter” is one
that is designed for operation in an interconnected grid, and without modifications to its control architecture
it may not be able to operate in an off-grid mode. The majority of IBRs in operation on the bulk power system
today utilize conventional inverters. The inner and outer control loops are shown. Most conventional inverter
controllers use the dq0 reference frame as shown in Figure C.2, but other structures are possible and are used.
The source of the dc link reference voltage VDC* varies depending on application. In PV inverters, VDC* may
be set by the outer power loop controller or the maximum power point tracker. VDC*_ref for type IV WTG
is a design value (constant) and, depending on design, it is the responsibility of machine-side or grid-side
converter to maintain the dc voltage across the capacitor (dc link).
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Associated Transmission Electric Power Systems
Figure C.1—Topological diagram of an IBR using a variable-frequency ac primary source
(top) and dc primary source (bottom)
VDC
PDC
VDC
PDC
calculation
IDC
1 = MPPT, torque controller, DC-DC
converter etc.
VDC
-
Σ
VDC
controller
Id*
+
+
Σ
-
PWM
generator
VDC*
Plant
controller
command
(Q,V,etc.)
Outer-loop local Iq
reference generator
Iq*
+
Σ
DC
link
Vd*
Id
controller
Vq*
Iq
controller
-
Vabc
PLL or
equivalent
Iabc
Vabc
Converter
phase angle
reference
Outer-loop local
active power
control
VDC
1
LV
AC
PT
phase angle
reference
Id
2
Iq
3
Iabc
Iabc
Vabc
CT
MV/HV
AC
Figure C.2—Block diagram of a conventional inverter controller
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Associated Transmission Electric Power Systems
A doubly-fed generator (DFG), also known as a doubly-fed induction generator (DFIG), doubly-fed
asynchronous generator (DFAG), or type III in the context of wind generation, is a special case that has a
different configuration, as shown in Figure C.3. Unlike a type IV wind turbine where the stator of the machine
is directly connected to an ac-dc-ac converter, as shown in Figure C.1, a type III wind turbine generator has
a back-to-back ac-to-dc-to-ac converter only in the machine’s rotor circuit, where it is sized to about 30% to
35% of the rated power of the machine. A machine-side converter is used to impose a voltage and current at
a controlled frequency on the machine’s rotor windings, establishing a precise amount of slip between stator
and rotor electrical frequencies. The mechanical input power is supplied through the rotor and is then
delivered to grid through the stator winding. If the mechanical rotor speed is supersynchronous, the grid-side
converter also delivers active power to the grid; otherwise, it absorbs active power from the grid. The use of
a back-to-back converter also allows the machine-side converter to modulate stator terminal voltage
magnitude to deliver or absorb reactive power from the grid. The grid-side converter can be used to
supplement reactive power to or from the grid respectively.
Type III wind turbine generators exhibit some inverter-like behaviors and some machine-like behaviors, and
overall the machine’s behavior can be somewhat complicated. For more information, the reader is referred
to Abad et al. [B1].
Figure C.3—Type III (DFG) wind turbine generator schematic
The plant and inverter controllers for the generic controls in Figure C.1, Figure C.2, and Figure C.3 are
described in more detail below.
a)
181
Plant controller: The plant controller in a conventional IBR plant is responsible for maintaining a
reference active and reactive power output from the IBR plant as a whole. In order to meet this
obligation, the plant controller uses measurements at the point of interconnection (POI) or another
relevant point to coordinate the operation of the inverters and supporting devices within the plant by
providing control commands and reference values. Typical functions implemented in the plant
controller include voltage support at the POI, and plant-level power limiting functions. The plant
controller is often an important information-gathering node and is frequently associated with the
plant-level SCADA system. In addition to the inverters, plant controllers may also command reactive
support devices such as capacitor banks or static var compensators (SVCs). Plant controllers for
modern, transmission-level IBR plants typically update the commands to the inverters at a rate of
once every 40 ms to 100 ms. 181
Note that this is the command update rate, not the response time of the system.
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Associated Transmission Electric Power Systems
b)
Inverter controller
1)
c)
Outer (slow) control loop (drawn using grey lines in Figure C.2)
i)
Outer-loop active power control. The outer loop active power controls regulate the transfer
of active power from the energy source. Examples include maximum power point trackers
(MPPTs) for PV inverters or torque controllers for type IV wind turbine inverters. The
outer loop improves the utilization of input energy (solar irradiance or wind velocity) by
locating and maintaining operation at the point where the dc-side power source produces
its maximum power. This applies primarily to PV inverters, where the loop adjusts the
voltage reference for the dc bus voltage regulation loop. In wind turbines, an equivalent
control loop adjusts the pitch angle of the turbine blade and the tip speed ratio of the rotor
to track an optimal point on an efficiency curve. This is the slowest of the inverter control
loops, and its operation rate varies from a 0.5 s to around 5 s depending on characteristics
of the dc-side source.
ii)
Outer-loop reactive power control. This function regulates the reactive power from the
inverter. The reference for this function is typically either a reactive power value or a
voltage magnitude value from the plant controller. Based on the plant controller input,
this block generates the reactive current command for the inner control loop. It is typically
faster than the outer-loop active power control, with typical response times on the order
of 250 ms to 1000 ms.
iii)
Active and reactive power calculations. Typically, the measurements fed into the active
and reactive power calculations undergo significant filtering, with concomitant time
delays.
Inner (fast) control loop (drawn using black lines in Figure C.2)
1)
DC bus voltage (Vdc) regulation loop: This loop controls the voltage on the dc link capacitor
by adjusting the magnitude of the active ac current (i.e., the active power flowing from the dc
link out to the grid). Because the output of this control loop is an input to the current regulation
loop, it is slower than the current regulation loop. Its typical operation rate is within one to six
cycles.
2)
Phase-locked loop (PLL): The PLL provides the waveform reference for the PWM generator
that commands the inverter’s insulated-gate-bipolar-transistors (IGBTs), and is responsible for
ensuring phase and frequency synchronization between the inverter’s output current and its
point of synchronization voltage. The PLL also provides the phase angle references that are
used in the dq0 calculations shown in Figure C.2, and the PLL often also provides the inverter’s
internal frequency measurements. Many different PLL architectures are used in industry, with
widely varying characteristics (with bandwidths ranging from a few hundred hertz to the
kilohertz range). The PLL’s characteristics are typically highly important in determining
inverter stability when connected to a “weak” grid.
3)
Current regulation loops: In a conventional inverter, the current regulation loops control the
active and reactive ac current injected by the inverter into the grid. Most three-phase inverters
control current in the dq0 reference frame. (Note that the dq0 calculation utilizes a phase angle
reference provided by the PLL, and thus PLL performance also impacts the performance of the
current regulation loops.) Assuming that the q-axis voltage at the point of synchronization is
zero (due to the angle generated by the PLL), active current is controlled by controlling the daxis component of the ac current, and reactive current control is implemented by controlling
the q-axis component of the ac current (with bandwidths ranging from a few hundred hertz to
the kilohertz range).
122
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Associated Transmission Electric Power Systems
CAUTION
Various controls can have impact on the inverter stability and should be properly modeled in sufficient
details to represent the performance of the IBRs under various system conditions. In a low system strength
condition, the plant controller should be properly modeled to consider its impact.
C.2 System strength and select metrics
C.2.1 System strength
The term system strength, or system stiffness, typically means one of two things:
a)
b)
System inertia, or df/dP, which classically refers to the ability of the system to resist changes in
frequency.
Source impedance strength, which refers to how high the impedance is to the grid voltage source as
seen from some point on the system relative to the size of a generator connected at that point. A
“weak” system has a high source impedance.
These two are in many ways interrelated, but for purposes of this document system strength refers to the
latter, the source impedance strength. Because low system strength can adversely impact IBR stability, it is
important to be able to assess the system strength as seen from the IBR during the design phase of IBR
deployment. There are several parameters that can be used to characterize the system strength, and the most
commonly used ones are described below, along with their limitations. In order to maintain consistency, these
descriptions borrow heavily from NERC’s guideline [B77] on integration of IBRs into high source impedance
systems and its parent CIGRE report (CIGRE TB 671 [B12]). It should however be noted that because of
complex interdependencies between inverter and power system characteristics, the metrics described below
should be applied judiciously. In general, the best that these metrics may provide is a highly conservative
threshold below which additional study should be conducted to help ensure stability. The value for these
thresholds can vary from one system to another, or even from one operation condition to another. It is
therefore generally not good practice to consider mitigation or redesign based solely on the value of these
system metrics.
C.2.2 Short-circuit ratio (SCR)
SCR is often used as a tool by planners to identify potential instabilities. However, any value of SCR intended
for use across an entire system should cover a variety of operating conditions and topologies. Unless validated
under specific constraints, SCR-based metrics should only be used as qualitative tools, and more rigorous
studies using electromagnetic transient (EMT) study tools should be used as a more reliable means to help
ensure that the IBR operates as intended.
The most basic and easily applied metric to determine the relative strength of a power system is the shortcircuit ratio (SCR). SCR is defined as the ratio between short-circuit apparent power (SCMVA) from a 3LG
fault at a given location in the power system to the rating (in MW) of the IBR connected to that location:
SCRPOI =
SCMVAPOI
MWIBR
(C.1)
where
SCMVAPOI is the short-circuit MVA level at the POI without the current contribution of the inverterbased resource
MWIBR
is the nominal power rating of the inverter-based resource being connected at the POI
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Since the numerator of the SCR is dependent on the measurement location, this location is usually stated
along with the SCR number. 182 This metric was developed as an aid in classical line-commutated converter
(LCC) HVDC design and is commonly used by the utility industry to quantify system strength. The effective
short-circuit ratio (ESCR), in which the short-circuit capacity at POI is decreased by the amount of shunt
capacitance MVAR at or electrically near the POI, may be used to accurately represent the increase of the
POI driving point impedance (decreased grid strength) caused by this capacitance. A low SCR (“weak
system”) indicates high sensitivity of voltage magnitude and phase angle to changes in active and reactive
power injections or consumptions at that location. A high SCR (“stiff”) location has a low sensitivity of
voltage to IBR output.
Because this sensitivity of voltage magnitude and phase angle to inverter injection can impact the stability of
grid-following inverters by effectively closing a loop between the inverter’s injection and the inverter’s point
of connection (POC) voltage, SCR can indicate situations in which grid-following inverters may experience
instability problems, with a “high” SCR reducing the risk of this type of instability and a “low” SCR
indicating elevated risk. However:

The SCR is based on the fundamental frequency impedence. Many IBR instabilities occur at higher
frequencies and require consideration of impedences at other than fundamental frequency.

The SCR is a convenient metric to use when considering a single inverter-based resource operating
into a relatively conventional power system because it uses readily available data and provides an
assessment of source impedance relative to the size of the IBR plant. However, the SCR has some
important limitations as a tool for assessing potential IBR stability.

SCR does not account for the presence of other inverter-based resources or power electronic-based
equipment electrically close to the POI under study.

The SCR provides a measure of system strength at a common location such as the MV bus or the
POI, which, because of IBR plant transformers and collector systems, can be significantly different
from the system strength as seen from individual inverters within an IBR plant.

The SCR calculation assumes that the power system consists of a well-regulated voltage source with
a simple series impedance. It does not consider the presence of load between the IBR and the
equivalent utility voltage source. The impact of a “weak system” on IBR stability depends on the
fraction of the IBR current travelling from the IBR (or group of IBRs) through the source impedance
to the equivalent grid voltage source. If a significant portion of the IBR current flows into local loads
and not through the source impedance, then the SCR gives an overly pessimistic assessment of the
potential impact on IBR stability. The SCR calculation also does not account for shunt capacitors
that increase the source impedance but do not impact the fault MVA.
For these reasons, the quantitative value of SCR is limited. Above some “high” SCR value, one can
reasonably assume that low-SCR instability is unlikely to occur. Below some “low” SCR value, instability
risk rises and additional study is prudent. However, because of the factors cited above, the definitions of the
“high” and “low” SCR values are not clear or unique, and there is generally a large range between the “high”
and “low” values in which SCR essentially provides no guidance.
SCR at the POI is typically used as a metric for planning. However, it is the effective system impedance at the equivalent inverter
terminals that is more indicative of inverter stability. For most IBR plants, the impedance between POI and POC of the equivalent
inverter tends to fall in a relatively narrow range. Thus, minimum SCR guidelines based on the POI location provide reasonable
consistency in most cases. Such POI-based SCR guidelines, however, can be misleading in cases where there is an atypical amount of
impedance between the POI and equivalent inverter POC, such as when there is a very long transmission tie line or extra stages of
voltage transformation, such as in offshore wind plants.
182
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CAUTION
The SCR is a simple way to make an initial assessment of system strength using readily available
information, but because of its limitations it should be used in IBR stability assessment primary as a rough
initial screen of whether additional, more detailed analyses are needed. SCR is often not appropriate when
an IBR plant is near other IBR plants.
C.2.3 Other SCR-based metrics
Several methods have been proposed to estimate system strength for groups of IBRs that are electrically close
to one another. Some of these are described below. Refer to CIGRE TB 671 [B12] for more detailed
examples. Like SCR, all of these methods have limitations, but may be useful for screening to determine
whether more detailed analysis is warranted.
C.2.3.1 Weighted short-circuit ratio (WSCR) 183
The weighted short-circuit ratio (WSCR) has been recently applied in the Electric Reliability Council of
Texas (ERCOT) to assist in defining operational limits for total transmission of power from IBRs across key
power system interfaces. WSCR is defined as:
WSCR =
∑ ( SCMVA × P
(∑ P )
N
i
i
N
i RMWi
RMWi
)
2
(C.2)
where
SCMVAi
is the short-circuit capacity at bus i without the fault-current contribution from the IBRs
PRMWi
is the MW output of non-synchronous generation to be connected at bus i
N
is the number of IBRs “fully interacting” with each other (“fully interacting” is discussed in
more detail below)
The WSCR is thus an SCR weighted according to the portion of the total IBR represented by the single IBR
plant under consideration. This is equivalent to assuming that all nonsynchronous generation plants are
connected to a virtual point of interconnection (POI). In practice, there is usually some electrical distance
between each nonsynchronous generation plant’s POI, and the nonsynchronous generation plants are not
likely to fully interact with each other.
C.2.3.2 Composite short-circuit ratio (CSCR)
The composite short-circuit ratio (CSCR) estimates the equivalent system impedance seen by multiple IBRs
by creating a common medium-voltage bus and tying all IBRs of interest together at that common bus. 184
The composite short-circuit MVA at the common bus without the fault-current contribution from the IBRs,
CSCMVA, is then calculated. Then CSCR can be calculated as
CSCR =
CSCMVA
MVIBR
(C.3)
This subclause is based on Zhang et al. [B114].
Details related to connection of medium-voltage buses of different voltages and specifics of using short-circuit programs for these
estimations are described in GE Energy Consulting [B27].
183
184
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Where MWIBR is the sum of the nominal power ratings of all IBRs being considered. This method calculates
an aggregate SCR for multiple IBRs, rather than one for each resource as in the conventional SCR approach.
This is equivalent to assuming that all IBRs are connected to a virtual POI (i.e., no impedance between the
IBRs). In practice, there is usually some electrical distance between the POIs of different IBRs, and thus they
are not likely to fully interact with each other.
C.2.3.3 Short-circuit ratio with interaction factors (SCRIF) 185
Other methods have been proposed that attempt to account for the impedances between the IBRs. This is
done either through impedance matrix manipulation, or calculated changes in voltage at all other locations
when reactive power is injected at each individual location. Although these methods are more rigorous and
allow consideration of each individual IBR in the presence of the others, they are more difficult to apply as
a screening method, and may be more difficult to determine what actions should be taken when these methods
are used as an area-wide operating screening tool.
SCR with interaction factors (SCRIF) has been proposed to capture the change in bus voltage at one bus
resulting from a change in bus voltage at another bus. Electrically-close IBR buses have a higher interaction
factor (IF) than IBR buses that are electrically separated. When multiple IBRs are located very close to each
other, they share the grid strength and short-circuit level; hence, the grid strength is actually lower than the
overall short-circuit level calculated at that bus or buses. SCRIF captures the voltage sensitivity between
inverter-based resources as a screening tool for potential controls issues by using inverter-based resource
interaction factors, as follows:
SCRIFi =
SCMVAi
Pi +
(C.4)
∑ ( IFji × Pj )
j
where
SCMVAi is the short-circuit MVA at bus i
Pi
is the active power of the IBR plant at bus i for whom SCR is being calculated
Pj
is the active power of the IBR plant at bus j associated with interaction factor IFji
IFji
is the change in bus voltage at bus i ( ∆Vi ) for a change in bus voltage at bus j ∆Vj , which is
( )
calculated as follows:
IFi j =
ΔVi
ΔV j
(C.5)
SCRIF is the only metric presented here that gives a reasonably accurate representation of the system strength
for individual IBRs within a larger group (e.g., for individual inverters within an IBR plant, accounting for
collector-system impedances). SCRIF can be useful when considering relatively large systems with large
numbers of IBRs, such that a direct EMT study of the entire system with all IBRs may not be feasible.
C.2.4 Application of strength metrics
SCR, WSCR, CSCR, and similar metrics should be carefully applied, understanding the assumptions and
limits of each metric. Both CSCR and WSCR calculation methods are based on the assumption of strong
185
This metric is titled “Equivalent SCR” in the CIGRE brochure, which is distinct from the classical “Effective SCR” used in LCC
HVDC design.
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electrical coupling among IBR plants. The CSCR and WSCR values typically give a more accurate estimate
of the system strength compared to SCR values when more than one IBR is present. However, they still do
not account for IBR-IBR interactions that may be influenced by that IBR-IBR impedance. For example, if a
system is determined to be extremely weak, such that a particular IBR is likely to have a stability problem,
the equation for SCR immediately suggests several mitigation solutions. Increasing the SCMVA at the
interconnection (increasing the numerator) directly increases SCR. Synchronous condensers, lower
impedance transformers, and additional interconnecting transmission all increase the short-circuit level and
generally improve weak system behavior. Conversely, decreasing inverter-based resource rating (decreasing
the denominator) also directly increases SCR, and is also effective to improve weak-system behavior.
However, in both cases care is needed. Adding synchronous condensers can introduce new modes of angular
instability and may also introduce protection and maintenance challenges. Reduction in active power from
the IBR through curtailment relieves stress on loaded lines and generally improves stability, but this approach
can leave a fully rated inverter (with associated voltage controls etc.) still actively connected to the same
grid. Other inverter-based equipment, such as SVCs or FACTs, are generally ignored in these calculations,
even though they also require a stable voltage for their own power electronic controls.
If applying one of the above-described metrics as a screening procedure (for example, WSCR should stay
above a given threshold), the threshold for WSCR calculated using MVA could be different from WSCR
calculated using MW. In this case, the WSCR metric could be applied both in terms of MW and MVA, as
expressed below. Equation (C.6) is Equation (C.2), repeated for convenience:
WSCRMW
∑ ( SCMVA × P
=
(∑ P )
N
i
i
RMWi
N
i RMWi
)
(C.6)
2
Equation (C.7) is Equation (C.6) re-expressed in terms of MVA:
WSCRMWA =
∑ ( SCMVA × P
(∑ P )
N
i
i
N
i RMVAi
RMVAi
)
2
(C.7)
where
PRMVAi
is the MVA rating of non-synchronous generation to be connected at bus i
Another limitation of the presented strength metrics is the fact that they provide information on the impedance
in the fundamental frequency only and neglect both subsynchronous and supersynchronous resonances. As
discussed in C.1, typical IBR has several “layers” of control, each being active within different frequency
range. The interaction between an IBR and network resonance or another IBR cannot be predicted by system
strength metrics. A frequency-dependent impedance should be analyzed in a large frequency range (Wang
and Blaabjerg [B112]).
General requirements for IBR to prevent any control interactions with the network are impossible to
guarantee by manufacture or developer, since it is originated not in the control, but in the combination of
control and rest of the grid.
There are several alternative metrics that might be used to analyze non-fundamental frequency behavior, such
as impedance-based stability analysis in the frequency domain or modal analysis.
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C.2.5 Comparison of system strength metrics
Each of the methods described in the preceding sections has benefits and drawbacks as a screening tool.
Table C.1 provides an illustrative description of the similarities, differences, benefits, and drawbacks of these
metrics. “No” entries mean that the metric cannot be applied for the described purpose. “Partial” entries mean
that the metric can be applied with some additional effort or processing, or can be applied to a limited extent,
and “Yes” entries mean that the metric is easily or directly applied for these purposes.
As discussed above, because of the complex dependencies and interdependencies on inverter and power
system characteristics, for none of these system strength metrics is there a crisp threshold value defined above
which stability is guaranteed and below which stability is known to be compromised. Thus, these metrics
should be applied judiciously, and in general the best that these metrics can provide is a highly conservative
threshold below which additional study should be conducted to help ensure stability. It is generally not good
practice to require mitigation or redesign based solely on the value of any system strength metric.
Table C.1—Comparison of system strength metrics
Metric
SCR
CSCR
WSCR
SCRIF
Short-circuit
ratio
Composite
SCR
Weighted
SCR
Multi-infeed
SCR
Accounts for
Able to
Provides
Simple
Accounts for
Considers
weak electrical
consider
common
calculation
nearby
non-active
coupling
individual
metric
using shortinverterpower
between plants
sub-plants
across a
circuit
based
inverter
larger group within larger
within larger
program
equipment
capacitya
of IBR
groups
groups
Yes
No
No
No
No
No
Partial
Yes
Yes
No
No
No
Partial
Yes
Yes
Partial
No
No
No
Yes
N/A
Yes
Yes
Yes
a
For example, static synchronous compensators (STATCOMs) or partial power IBRs. Note that any of these can be calculated using
MW (Equation [C.6]) or MVA (Equation [C.7]) to consider non-active power inverter capacity as desired.
Each metric has benefits and drawbacks in its application for assessing system strength and potential weak
grid issues. These may include:

Simple calculation using short-circuit programs: Metric utilizes positive-sequence short-circuit
program for primary results. Some simple additional manipulation or post-processing may be
required.

Accounting for nearby inverter-based equipment: Metric inherently considers the presence of
nearby inverter-based equipment, particularly if the equipment is electrically very close.

Common metric across large group of inverter-based resources: Metric provides a single
consolidated value for all the plants within the selected group.

Accounts for weak coupling between plants within larger group: Metric is able to consider the
isolating effect of impedance between inverter-based resource plants, or to consider that each plant
may be obtaining system strength from different sources. (As opposed to assuming plants are
perfectly coupled—essentially a single plant.)

Considers non-active power inverter capacity: Metric accounts for capacity of inverters nearby
that may require a strong system, but do not generate active power. Examples could be curtailed
IBRs, STATCOMs, or SVCs.
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
Considers individual sub-plants within larger group: Metric provides a system strength value at
any number of individual buses within a group, accounting for the presence of the other IBRs in other
buses within a group.
C.2.6 Limitations of screening metrics

The temptation for planners is to apply screening metrics in a general way to determine whether their
system can operate correctly. However, while a lower (higher) SCR generally increases (decreases)
the likelihood of problems occurring, because the value of SCR at which such problems occur
depends strongly on the location within the system, the types of equipment and firmware used,
specific combinations of equipment and firmware, measurement and communications latencies, and
other ill-defined factors, any single threshold value of SCR intended for use across an entire system
should be significantly conservative to help ensure that it covers all cases. This means that many
IBRs that may not experience any low-SCR issues in the field may be “flagged” by the SCR
threshold. For this reason, SCR-based metrics should be used as screening tools, be based on
minimum short-circuit currents, and if an SCR-based metric indicates a potential problem, more
rigorous study using electromagnetic transient (EMT) study tools should be conducted to help ensure
that the IBR operates as intended. In addition, the SCR is based on the fundamental frequency
impedence. Many IBR instabilities occur at higher frequencies and require consideration of
impedences at other than fundamental frequency.
CAUTION
The SCR-based metrics should be used carefully understanding the assumptions and limitations of usage of
the selected SCR-based metrics. When in doubt, EMT studies should be conducted to investigate and verify
IBR stability.
C.2.6.1 Use of computer modeling to quantify potential stability problems
If an SCR-based screen indicates that the system strength at a particular POI is low enough that a stability
issue may arise, it is possible to use computer modeling to assess whether an IBR may encounter a stability
problem due to low system strength at a particular POI. For this type of study, the following guidelines should
be observed.
a)
The study should be conducted using an EMT simulation tool, such as MATLAB/Simulink, EMTP®,
PSCAD, or similar.
The power system representation should be adequate to capture the characteristics of the system as
seen from the POI, at the frequency range appropriate for the phenomena being studied. The
transmission system “upstream” from the POI should be represented in sufficient detail to capture
nearby capacitors or other var sources, any nearby buses with generation of any type or energy
storage, and load taps, especially those between the IBR(s) under study and the highest-impedance
elements along the path back to the transmission system’s sources of power. Any significant loads
along the path back to the transmission system’s sources of power should also be included in the
model. Unless the transmission system serving the POI is extremely simple, reducing that entire
system to a Thevenin equivalent is generally an insufficient representation.
b)
The model used for the inverters within the IBR plant should be a manufacturer-specific model that
captures all relevant details of the PLL, the inner and outer control loops, all measurement filters and
latencies (e.g., sampling), control-code execution rates (e.g., loop execution times), and the passive
elements of the ac and dc buses. A model that utilizes the actual control code from the inverters is
strongly preferred for this type of study. An averaged model of the power stage can be used because
switching-frequency dynamics are not usually important in studies of low-SCR instability issues, but
typically the highly-detailed models provided for this purpose are full-switching models. Before
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using an inverter model in a low-SCR instability study, the inverter model should be tested by a)
verifying with the manufacturer the SCR at which the manufacturer expects instability to appear at a
specific Xgrid/Rgrid value; and b) running the inverter model in a test circuit with the proper SCR and
Xgrid/Rgrid to verify that the model does indeed exhibit the expected behavior described by the
manufacturer.
c)
Whether any IBR plant in an EMT study can be represented as an aggregate (i.e., one scaled instance
of the model with an aggregated collector-system impedance), or in detail (i.e., each individual
inverter and details of the collector system), depends on the specifics of the inverters and IBR plant
configuration. It is recommended that if any aggregated IBR plant model is used, it should be
validated against a detailed, disaggregated model of that IBR plant for at least a small number of key
cases to help ensure reasonable representation of key behaviors.
C.3 Inverter-based resource stability
When the system evolves with increasing penetration of IBRs, inverter stability should be assessed. Inverter
instability and interactions with other devises can occur due to various reasons, including system condition,
improper control settings, and resonance with other generation and transmission facilities. The dynamics of
IBRs can bring in instability and resonance in a wide frequency range. Inverter instability issues described
in this section include a high-level background, a methodology or industrial practices to identify these issues,
and mitigation options to address instability. An overview of some of the instability issues that can occur
under low system strength conditions and interactions with generation and transmission facilities are
provided in this section. The described methodologies and process may also be applicable to identify other
inverter instability issues not covered in this section. The most important aspect of identifying and mitigating
issues related to integrating IBRs into a low system strength grid is coordination and communication between
the transmission planner, generator owner, and manufacturers.
C.3.1 Inverter instability
C.3.1.1 Voltage stability
A low system strength grid has a comparably small short-circuit current, and causes higher dV/dP and dV/dQ
sensitivity. These increased sensitivities can lead to a higher risk of voltage instability and collapse.
The increased active power variability of IBRs, their integration into sparse electrical networks, and their
controls can potentially produce low system strength issues that may not generally be studied or as closely
considered as synchronous resources. With the increase of IBRs connected to the low system strength grid,
planners should identify the potential system conditions that can cause voltage instability and mitigate those
issues.
The system conditions that can lead to low system strength, and which should be assessed include but are not
limited to: high IBR outputs, fewer online synchronous generators, large transfers, and planned or forced
outages.
Mitigations related to the plant-level control of IBRs to resolve the voltage stability issues include but are
not limited to: voltage profiles, voltage control mode of IBRs, and voltage support capability.
CAUTION
For inverter-based resource plants, although generally capable of operating in constant reactive power
mode or constant power factor mode, should operate in closed-loop voltage regulation mode to improve the
voltage stability and power transfer capability.
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C.3.1.2 Control instability
One of the important modes of control instability in IBRs relates to interactions between fast, high gain
controllers of power electronic resources, such as IBRs or FACTS, and relatively high impedances
connecting the resource to the power system. The open loop gain as experienced by the interacting controllers
is higher when they are connected and operated in low system strength grids, making them more susceptible
to control instability such as oscillations, unit tripping, or power quality concerns. These control instability
concerns are usually functions of the linear control regions and the network impedance, and are often
characterized by oscillations occurring under normal or small disturbance conditions. Figure C.5 (Huang et
al. [B29]) shows the PMU recorded oscillation when a type IV wind plant was connected to a low system
strength grid, where no system disturbance initiated the oscillation. A typical solution to this type of behavior
is to re-tune the IBR controller.
Figure C.4—Recorded unstable response for a wind plant connected to a weak
transmission grid
Another mode of control instability relates to the specific control and protection configurations of IBRs. They
can include non-linear controls or control-mode changes which activate during system disturbances or
external events. Figure C.5 shows an example of wind plant control instability. This instability is essentially
a form of “chattering” in which the wind plants enter voltage ride-through mode resulting in reduced active
power, allowing the voltage to recover at which point the wind plant leaves the reduced active power mode
and the cycle repeats. Voltage is plotted for several transmission buses during the event.
Figure C.5—Example of control instability (mode cycling) at wind plants connected to a
weak grid
Another form of control instability called harmonic instability can appear in “strong” networks (i.e., those
having a high SCR). This phenomenon can occur due to the active nature of the IBR’s impedance, which can
result in instabilities (e.g., negative resistance). Typically, the term harmonic instability refers to oscillations
at a frequency above the fundamental frequency in the synchronous reference frame, but many of the
mechanisms that result in oscillation at frequencies below the fundamental frequency can also be traced back
to a negative resistance resulting from dynamic IBR impedance.
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Finally, it is also possible that IBR plant controllers may interact with one another in unstable ways. These
instabilities can be detected via EMT simulation using code-based models of the inverters in the IBR plants.
Mitigation generally involves retuning of the controls in one or both IBR plants.
These types of control interactions and instability are often not detectable using existing state-of-the-art
positive-sequence simulation tools. These tools usually do not include the plant-level voltage control and fast
controllers, such as phase-locked loop and inner current controllers, that are responsible for the unstable
modes, and are either not included or greatly simplified. To identify these control instabilities, the following
should be considered:
a)
System conditions: The system performance can be affected by IBRs’ capacity and dispatch, system
topology, and short-circuit current level. Various system conditions should be considered when
evaluating the control instability in a low system strength grid.
CAUTION
Factors that can affect system performance include but are not limited to: IBR’s capacity and dispatch,
system topology, short-circuit current level, and voltage controllers in the generators and FACTS devices.
These factors should be considered when evaluating the control stability of IBRs connect to a low system
strength grid. A screening tool or metric should only be used as a reference and is highly dependent on each
system characteristics. There are no universal thresholds or metrics.
b)
The adequacy of simulation model and programs: Although the positive-sequence simulation
programs are widely used to evaluate stability of the BPS, they often use simplified models in which
fast controllers are typically represented as constants or simple algebra equations. Furthermore, they
are inherently limited to representation of only the transmission system (TS) fundamental-frequency
characteristics that makes them invalid tools for interactions and instabilities occurring above a few
Hz in the synchronous reference frame. Although generic models or manufacturer provided userdefined models may have the best approximation of specific equipment in the positive-sequence
domain, for a low system strength application the limitations of models and tools should be
recognized and available to the system planners and operators. Electromagnetic transient programs
should be used if an IBR connects to a low system strength grid. Further, use of newer improved
positive-sequence models that have explicit representation of the fast phase-locked loop and inner
control loops should be explored.
CAUTION
Positive-sequence simulation programs may not be adequate to evaluate the stability of IBRs connected to a
low system strength grid. EMT simulation program should be used to evaluate the stability of a low system
strength grid.
CAUTION
Dynamic model quality tests to evaluate the model performance under various system strength conditions
should be considered. The model performance between positive-sequence and EMT models should be
compared under various system strength conditions.
Mitigations related to the IBRs’ control instability include, but are not limited to:
a)
System reinforcement: New transmission circuits can reduce the system impedance, but it may not
be a viable option due to its expensive cost and long lead implementation time. Series capacitors can
also be considered to reduce the impedance. However, the subsynchronous instability concerns,
which are described in the following section, should be considered. Synchronous condensers are
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presently the primary solution to improve the system strength because of multifaceted benefits
including large capability to supply fault current, inertia, and voltage support capability. However,
synchronous machine stability should be considered when recommending synchronous condensers.
b)
Controller changes: PLL, inner loop current control, and plant-level voltage control are three key
controllers in the IBRs that can cause control instability in a low system strength grid. Changes to
these controllers are typically done by the manufacturer. In some cases, changes to these controllers
may alleviate the issues related to low system strength. Changes to the plant-level voltage control
generally include time constants and gains. They are typically adjusted to have slower response for
a low system strength application. Voltage droop can also be deployed to reduce inter-plant control
interaction. Changes to the PLL and inner loop current control loop may require complex engineering
efforts. Control instability issues cannot always be fully addressed with controller changes.
Controller changes are often system specific and should be determined in close coordination between
the transmission planners, generation owners, and manufacturers. IBR controller tuning may also
need to be reviewed if significant changes are made to the transmission system or connected
resources, and changes to these controls may necessitate changes to other system controllers, or
requirements for new system controllers (see C.4).
c)
FACTS devices: SVC and STATCOMs can help provide dynamic reactive support to control the
voltage fluctuations as well as help with transient ride-through capability. However, these devices
themselves have fast control loops and care should be taken as these devices may also be subject to
low system strength control instability.
b)
Reduction in plant capacity or output: System strength can be improved by either reducing the plant
capacity or limiting plant output. Although this option may not be a desired option, it is often the
only viable short-term solution if control instability is encountered in real-time or near real-time until
a longer-term solution can be implemented.
C.3.2 Subsynchronous instability involving transmission elements and rotating machines
Two types of subsynchronous interactions have been documented in the literature, as they pertain to
interactions between devices on the transmission system and rotating generation. These are subsynchronous
resonance (SSR) (Anderson and Farmer [B3]) and device-dependent subsynchronous oscillations (DDSO)
(IEEE Subsynchronous Resonance Working Group [B66]). DDSO can manifest when there is an interaction
of a turbine-generator with fast acting controllers (e.g., IBR controls) in the power system. The most common
example is between inverter 186 controls and the torsional mechanical modes of oscillation of nearby turbinegenerators—this is sometimes more commonly referred to as subsynchronous torsional interaction (SSTI).
SSR occurs when there is a resonance between generator(s) and a series capacitor on the transmission system.
The most common type of SSR, seen with conventional synchronous generation, is a resonance between the
series-compensated transmission system and torsional mechanical modes of oscillation of nearby turbinegenerators. A second type of SSR is also possible, namely the induction generator effect (IGE) or sometimes
referred to as self-excitation (Anderson and Farmer [B3]). The IGE-SSR (or self-excitation of induction
generators) is a purely electrical sub-synchronous resonance and is not related to the turbine-generator shaft
or mechanical system. This type of resonance is entirely driven by the electrical characteristics of the
induction generator and series compensation. Theoretically, this IGE is also possible on synchronous
machines (NERC Reliability Guideline [B76]), but this has never been reported in the field with synchronous
generation. Self-excitation IGE-SSR occurs when the series capacitor forms a resonant circuit, at subsynchronous frequencies, with the effective inductance of the induction generator, and at the same frequency
the net resistance of the circuit is negative (since the negative resistance of the induction generator rotor
resistance, as seen on the stator side, can become negative enough to override the remaining positive
resistance of the circuit). It is this type of SSR (i.e., IGE-SSR) that manifests itself with wind turbine
generators (WTG), and the type of WTG that is most susceptible are type III WTGs. 187 The reason for this is
twofold: (i) the induction generator employed in a type III WTG is directly connected to the grid (through its
This interaction was first observed with HVDC, but this interaction can potentially involve any type of IBR.
Type II variable-rotor resistance induction generator WTG technologies (and perhaps even type I WTGs on start-up), might also be
susceptible to IGE SSR. However, these technologies are no longer manufactured for large wind power plants and although in some
regions significant amounts of these older technologies still exist, they are no longer deployed for new wind power plants.
186
187
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stator) and thus the resonant circuit between the inductance of the machine and series capacitor can easily be
established when there is a radial configuration leading to the series capacitors, and (ii) the back-to-back
converter between the stator and rotor circuit of the type III WTG has a tendency to effectively increase the
rotor-circuit resistance, which thus increases the effective negative resistance as seen from the stator side
(due the inherent slip effect of an induction generator). Thus, the very significant additional negative damping
from the converter controls typically tips the balance and renders the resonance unstable. For this reason, this
SSR in the context of WTGs has been often called subsynchronous control interaction (SSCI) in the literature.
However, it is important to fully appreciate the mechanism, as explained above. Namely, that the primary
path of resonance is between the directly-connected induction generator and the series compensation. The
converter controls are then the significant source of negative damping. It is also possible to partially mitigate
the problem through supplemental controls in the type III WTG converter controls (Larsen [B68]). SSCI for
type III WTG has been seen as the controller-driven IGE effect and real field traces of currents in a type III
DFG wind farm could rise to over 4 p.u. in less than 0.5 s. Such phenomena require detailed and careful study
with vendor-specific EMT modeling.
Other power electronic devices like type IV WTGs, battery storage devices, STATCOMS, and SVCs,
although not recorded as having caused actual major damaging control interaction events, may still be
vulnerable to control interaction phenomenon with improper controller design and settings.
C.3.2.1 Subsynchronous instability identification
Typically, when an IBR is operated into a series-compensated transmission system, radial or near radial, care
should be taken since instability can quickly result in significantly high voltages and currents, leading to
tripping of IBRs, bypassing series capacitors, or physical damage to both turbines and series capacitors.
Although it typically requires detailed modeling and assessment techniques, such as EMT analysis, to identify
and address the subsynchronous instability, screening methods may be used to help whether a detailed
analysis is necessary to determine the subsynchronous instability. Various screening methods, like frequency
scan and eigenvalue analysis, may be used to initially assess the potential subsynchronous instability based
on the system conditions and model availability.
Small signal oscillations in the sub-synchronous frequency range can also occur due to instabilities in the
IBR control systems when connected into very weak ac networks. This can also lead to IBR tripping and
system instabilities, and also may require the use of EMT tools to effectively analyze.
One commonly used screening method in the industry is frequency scan. The frequency scanning method
looks for total impedance of IBR and the connected electric grid. In order for the IBR to have an unstable
interaction with the grid, the reactive components of the IBR and grid impedances need to have equal
magnitude and opposite sign to create a natural frequency, which is generally in a subsynchronous frequency
range from 5 Hz to 55 Hz but can also be in a supersynchronous frequency range under particular conditions.
In the frequency regions where IBRs have a negative resistance characteristic (necessary for instability
because the grid resistance is always positive), the instability can occur under various system conditions. As
a result, the following conditions should be included in the analysis to capture a range of controller, IBR plant
operating conditions, and system topologies. This list is not comprehensive.

Generation dispatch level

Number and availability of inverters in operation

Unity, capacitive, and inductive reactive power generation

Low, medium, and high perturbation magnitudes

Series compensation level if applicable

Status of switch shunts and synchronous generators

Transmission outages, switching, or contingencies
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CAUTION
When evaluating the subsynchronous instability, various conditions including, but not limited to, IBRs’
controls, IBRs’ operating condition, and system topologies should be assessed.
Note that the presence of many IBR devices may confound these screening approaches and cause them to be
invalid. Subsynchronous stability studies may require revision or repetition periodically as system conditions
change and additional IBR devices are added to the system. Frequency scanning methods are approximate
and should only be considered as screening tools. Detailed assessment is usually required to finally determine
stability.
CAUTION
Although screening methods may help identify the potential subsynchronous instability, a detailed
assessment like an EMT study is usually required to determine risk and develop mitigation plans.
C.3.2.2 Subsynchronous instability mitigation
Mitigations related to the IBRs’ subsynchronous instability include but are not limited to:
a)
Bypass series capacitor(s): Bypassing series capacitor(s) is often considered to mitigate the
subsynchronous instability under normal and outage conditions. However, the impact of transfer
capability and other stability concerns, such as angular and voltage stability, should be evaluated
when recommending this option. Also, the speed of bypassing series capacitors should be evaluated
because subsynchronous instability can occur in less than 30 cycles.
b)
Controller changes by the manufacturer: Manufacturers of modern IBRs have developed
subsynchronous instability mitigation capability in the controllers. Dynamic frequency scans may be
conducted on high-quality black box inverter control EMT models to provide some sense of damping
at various frequencies. If instabilities or tripping are observed in simulation or in the actual system,
it may also be useful to provide information about the system impedance to the manufacturer so that
they may evaluate whether this is due to their control damping, and potentially re-tune their controls.
If there are multiple IBRs close to the series capacitors, all the IBRs should be included in the
controller tuning evaluation to properly include the nearby IBR’s impact.
c)
Subsynchronous instability protection: Manufacturers of modern IBRs have developed protection
capability to disconnect IBRs when detecting subsynchronous instability. Any potential adverse
impact should be evaluated if the capacity of IBRs to be tripped can cause the frequency or voltage
issues.
d)
FACTS devices and transmission enforcement: Reconductoring, the addition of new circuits or
FACTS such as SVC, STATCOM, and TCSC may be designed to provide damping and effectively
eliminate the subsynchronous instability. However, limited industrial experience and expensive cost
may prove challenging.
C.3.2.3 Subsynchronous torsional interaction identification and mitigation
A screening method to determine the risk of an IBR plant negatively impacting the torsional stability of a
thermal generator consists of calculating the unit interaction factor (UIFi). Equation (C.8) has been
established empirically under EPRI RP1425-1 (Oct. 1982):
=
UIFi
MVAIBR
MVAi

SCi 
1 −

 SCTOT 
2
(C.8)
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where
UIFi
is unit interaction factor of ith unit
MVA
is rating as per subscript (IBR or ith unit)
SCTOT
is short-circuit capability at POC including ith unit
SCi
is short-circuit capability at POC excluding ith unit
The screening method is a high-level approximation to estimate the potential SSTI risk and the application
of this screening method may not be applicable in a series-compensated transmission grid. Detailed
assessment including EMT analysis is usually required to finally determine stability. Simiarly, SSTI can
occur under various system conditions, as a result, the SSTI study should be included but not be limited to
the following conditions: status of the nearby generators, system topology, and IBR control characteristics.
Mitigations related to the SSTI include but are not limited to retuning of IBR controls, separate damping
control functions, special protection schemes to trip either the IBR or the turbo-generator for extreme
contingencies establishing a high UIF, or installation of torsional protection relays on turbo-generators.
C.4 Grid-forming inverters
Many TS operators have identified upcoming challenges to operate their grid in a stable and reliable manner
where synchronous generators are largely displaced by various types of IBRs. Existing control architectures
used by the majority of inverter-connected generation can be broadly termed as “grid-following”
architectures in which the IBR essentially acts as a power-regulated current source from the perspective of
the grid. Grid-following controls work well when connected to a reasonably strong ac power system where
there is only a small change in voltage at the terminals of the inverter for a change in the IBR-injected
current. 188 However, as has been discussed above, in relatively weak grids such an approach can lead to an
instability in the phase-locked loop (PLL) and associated controls of the IBR as it tries to track the grid
voltage phasor.
In order to operate in a weak-grid environment or in a system in which much of the generation is provided
by IBR, a change in the present structure of inverter control architecture may be required either through the
addition of supplemental outer slower control loops, or through alternate faster inner control loops. This
control architecture change may also be accompanied by changes in inverter hardware capabilities. In
research literature, these modified IBRs that are capable of operating in a stable fashion in weak ac systems
or in an islanded electrical grid have been given the name of “grid-forming” inverters. Historically, “gridforming” inverters have simply been inverters that independently regulate voltage and frequency, and thus
could be used for off-grid operation (i.e., they can form their own grids). However, as of this writing, the
precise meaning of “grid forming” is still in some flux. Thus, caution should be exercised when using this
terminology: use of terms such as “grid following” and “grid forming” should be accompanied by context
that describes the reasonable expected performance required from the IBR by the bulk power system.
CAUTION
Because the terms “grid following” and “grid forming” do not yet have universally accepted definitions, the
use of these terms (both from the TS owner when specifying interconnection requirements and from the
electromagnetic transient [OEM] when describing features of their products) should be accompanied by
additional contextual text that describes the reasonable expected performance required from (or can be
delivered by) the IBR by (to) the bulk power system.
188
This essentially means that the equivalent impedance looking into the grid is quite low. Alternatively, another metric
often used is short-circuit ratio (SCR).
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At a high level, the control strategies might be classified as follows:
a)
Existing control strategies that primarily rely on using a PLL to lock onto the grid phasor and have
fast inner-current control loops to regulate the active and reactive current injected by the IBR. In
these strategies, the regulated quantities are the ac active and reactive current or power. These are
“grid-following” types of strategies.
b)
Control strategies for islanded operation, in which the IBR’s regulated variables are voltage and
frequency. Historically, these have been referred to as “grid-forming” controls.
c)
Enhanced future control strategies where the IBR still utilizes a synchronizing mechanism (like a
PLL) to lock onto and keep synchronism with the grid, but may employ additional supplemental
control loops and features to better stabilize its response in weak grid conditions. Here, the IBR
control provides a constant voltage angle and magnitude behind an impedance in the period following
a change in terminal quantities. This period of constant voltage can be as short as a few milliseconds
in some schemes, or effectively continuous in other schemes. The characteristics of the
synchronization period following this initial response due to the transient constant voltage may also
vary depending on the control scheme used. Such control schemes can also generally be placed into
the category of “grid-forming” strategies, but as noted above, further context should be provided for
clarity regarding what “grid forming” means for a particular control strategy.
Across the industry, there is not yet a formally accepted definition of the performance and services expected
from grid-forming inverters. Simultaneously, drawing on salient features of the different control strategies,
inverter manufacturers may also use a combination of these control strategies resulting in a hybrid control
scheme. However, conceptually, the expectation is that these inverters would be able to serve local load in a
stable, reliable, and secure manner under both electrical and/or physical isolation from the rest of the bulk
power system with few or no synchronous machines present. Further, when connected in an interconnected
network with various types of resources, similar to the expectations placed on existing IBRs, these inverters
would be expected to operate harmoniously with the other resources. The “grid-forming” inverters are
expected to contribute to system strength, reducing the grid impedance and increasing the voltage stiffness
at the connection point. Installation of some “grid-forming” inverters would help to integrate more “gridfollowing” inverters. Therefore, in an IBR plant, “grid-forming” inverters might be used either in the IBR
itself or as a supplemental IBR device.
Changes to the control loops to help ensure stable and reliable operation under fast varying system conditions
likely requires consideration of associated hardware impacts. Sufficient current and energy headroom should
be available for the inverter all the time it is operated as grid forming. It is expected that the inverter protects
itself from overcurrent. Once the current limit is reached, inverter cannot operate as grid forming and has to
switch to a different mode of operation to respect the hardware limits. Such overcurrents are very likely to
occur during sudden large voltage changes (e.g., a short-circuit fault). Similarly, sufficient energy headroom
should be always present for the inverter to be able to respond to sudden phase angle jumps in the grid. Lack
of stored energy or, on the contrary, not enough room to absorb energy from the grid results in the limitation
of grid-forming mode. Most likely, grid-forming inverters have two modes of operation—(i) actual grid
forming, as long as there is sufficient headroom in current and energy; (ii) restricted mode, once the hardware
limits are reached. The impact of the transition from one mode to another on the system reliability has to be
carefully considered.

The grid-forming control might be implemented in inverters that are used only for the purpose of
grid stability or as an additional control feature (e.g., photovotaics, wind, or energy storage systems).
In this case the capacity of inverters “to provide grid forming” is defined not by the nameplate rating
of the inverter, but by the available headroom in current and energy that need to be allocated for gridforming operation. An IBR plant could provide grid-forming services to the bulk power system using
a variety of different methods, some of which are as shown in Figure C.6.
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Collector Bus
POM
POC
Intertie
Line
Transmission
System
Inverter
Main
Transformer
Compensation
POI
Collector Substation
Option 1:
Some of the IBR inverter
serves as “grid forming”
Option 2:
An compensation device
within an IBR plant serves
as “grid forming”
Stand alone IBR
Plant for
compensation device
Option 3:
A stand alone “grid
forming” device be
shared among several
“grid following” IBRs
Figure C.6—Grid-forming options
Uncertainties with these impacts exist, but some considerations that should be evaluated include:

Power electronic hardware design and rating—How much energy storage is needed (for frequency
support and stabilization)? How much should the inverter and energy source be oversized for fast
current injection (voltage recovery and tight voltage control)?

Control software development: Harmonics, frequency responsive ride-through, normal operation,
stability, etc., should be considered under revised control architectures.

For wind turbines, the energy yield, blades, mechanical drivetrain, tower structure, and foundation
design should all be reviewed.

Reliability impact—Increased reactive power or current requirements may change the thermal
management needs of the inverters to maintain high reliability.

Implications on product cost (capital expenditure), wear and tear and service cost (operational
expenditure).

Testing and validation: A clear roadmap (time horizon) to develop and master the technology if the
“go” is given should be developed.
For the TS operator it is also very important that future generation resources do not influence the grid with
unintended or unpredicted characteristics that could be very costly to correct. For TS operators, the challenges
can be stated as follows:

What is the achievable level and exact nature of system support that can (and should) be expected
from IBRs in a predominantly or fully IBR-supplied energy scenario, and what is the associated cost
of procuring such support?

What are the limits to stable operation of existing and new IBRs?

How would a variety of grid-forming control algorithms synchronize with each other?

How to help ensure grid-forming control algorithms operate in a stable fashion in coordination with
existing grid following control algorithms?

An IBR with grid-forming control should not be directly compared with a synchronous generator.
The goal is not to attempt to precisely “emulate” the behavior of synchronous machines, although
there are elements of this behavior which are desirable, in alignment with existing operation mode of
the system. As the grid moves toward an increased percentage of IBR the system’s stability properties
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and behaviors change, and IBRs can have desirable behaviors that synchronous generators cannot
reproduce.
CAUTION
The objective of grid-forming IBRs should not be simply to reproduce the behavior of synchronous
machines. Instead, the focus should be on understanding the needs of the evolving power grid and utilizing
the IBRs in the most effective way.
There is a lot of concern with loss of system inertia and TS operators and regional reliability coordinators
are increasingly monitoring this metric. But system inertia is just one of the several physical aspects that are
concerning system operators. Others include:

The reduction of short-circuit current in future systems. A lack of short-circuit current could
negatively affect the coordination of protection systems.

Reduction in damping torque for stabilization of remaining synchronous generators.

Increase in network impedance leading to instability of existing IBRs’ control-loop structures, which
may be addressed by new supplemental controls.

Frequency control from wind and solar generators (including maintaining reliable quantities of
reserve).

Transmitting power from new resource areas to existing load areas.

Lack of visibility/control of large numbers of small generators.
While IBRs have been used for black-start (e.g., voltage source converter high-voltage direct current [VSCHVDC]), requirements of black-start capability can be more demanding than grid-forming capability. Thus,
black-start requirements for IBRs participating in system restoration should be clearly defined by the TS
operator. Starting up a standalone IBR plant by itself and then to start delivering electricity in a grid that is
already up and running poses less challenge than when compared to network restoration of a blacked-out
network. Capability of IBRs with respect to the designated cranking paths needs to be studied in detail,
considering cold load pick up, in-rush current of transformers, and induction motors. Dispatchable IBRs
could be capable of operating as a black-start resource if they are given adequate design consideration. Blackstart service from BPS-connected IBRs should be implemented in coordination with the TS operator.
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Annex D
(informative)
Illustration of voltage ride-through capability requirements
This annex is informative. It is intended to help readers understand the voltage ride-through capability
requirements specified in 7.2.2.
D.1 Interpretation of voltage ride-through capability requirements
The voltage versus time curves in Figure D.5 through Figure D.8 built using voltage ride-through
requirements specified in Table 11 and Table 12 could be interpreted in a few different ways. These are:

The voltage versus time curve: For a given voltage, the IBR plant shall not trip until the time duration
at this voltage exceeds the specified minimum ride-through time duration. This is the interpretation
used in this standard.

Area represented by voltage deviation multiplied by time duration: Area between nominal voltage
and either a low- or high-voltage ride-through boundary.

Voltage versus time envelope: Voltage ride-through boundaries define an envelope to lay as a
template over a voltage versus time trajectory (simulated or recorded during an event) to determine
whether the trajectory remains within or departs from the ride-through zone.
The voltage ride-through capability requirements specified in this standard are neither an area represented by
voltage deviation multiplied by time duration nor voltage versus time enevelope. The correct interpretation
is the first interpretation above, that the IBR plant shall ride through when the applicable voltage exceeds or
is less than the voltage representing the continuous operation region except for time durations exceeding
those specified in Figure D.5 through Figure D.8. For example, the IBR plant consisting of wind turbine
generators, regardless of type, is required to ride through a voltage dip of 40% (i.e., 60% voltage at the
reference point of applicability (RPA) for a minimum time of 2.5 s. Additionally, the required minimum ridethrough time duration is a cumulative time within a 10-s time window.
Figure D.1 shows an event where voltage at the RPA drops to 60% of nominal for 2.0 s. The time duration
of voltage dip is less than required minimum ride-through time of 2.5 s, hence, the IBR plant is required to
ride through this voltage disturbance.
Figure D.2 shows an event where voltage dips multiple times within a 10-sec time window. The total time
duration of voltage dip is 2.0 s, which is less than required minimum ride-through time of 2.5 s, hence, the
IBR plant is required to ride through these voltage disturbances.
Figure D.3 shows an event similar to one shown in Figure D.2. However, in this case, the total time duration
of voltage dip is 3.0 s, which is greater than required minimum ride-through time of 2.5 s, hence, the IBR
plant is not required to ride through these voltage disturbances.
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100%
Voltage (percentage)
90%
80%
70%
60%
50%
2 sec.
2.0
1.0
3.0
4.0
Time (Seconds)
5.0
6.0
Figure D.1—Voltage ride-through requirement, example 1
100%
Voltage (percentage)
90%
80%
70%
60%
50%
1 sec
1.0
1 sec
2.0
3.0
4.0
Time (Seconds)
5.0
6.0
Figure D.2—Voltage ride-through requirement, example 2
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100%
Voltage (percentage)
90%
80%
70%
60%
50%
2 sec.
1.0
2.0
1 sec
3.0
4.0
Time (Seconds)
5.0
6.0
Figure D.3—Voltage ride-through requirement, example 3
Figure D.4 shows a realistic and complex trajectory of a voltage during a disturbance.
 During this event, the voltage never goes below 10%, thus IBR units at this facility are not expected
to block current injection.
 The total cumulative time within a 10-s window where voltage remains below 0.25 per unit is 0.1 s,
which is less than the minimum required ride-through time of 0.16 s. Hence, the IBR plant is required
to ride through.
 The total cumulative time within a 10-s window where voltage remains below 0.50 per unit is 1.1 s,
which is less than the minimum required ride-through time of 1.2 s. Hence, the IBR plant is required
to ride through.
 The total cumulative time within a 10-s window where voltage remains below 0.70 per unit is 2.4 s,
which is less than the minimum required ride-through time of 2.5 s. Hence, the IBR plant is required
to ride through.
 The total cumulative time within a 10-s window where voltage remains below 0.90 per unit is 4.0 s,
which is greater than the minimum required ride-through time of 3.0 s. Hence, the IBR plant may
trip.
For the IBR plant consisting of photovoltaic (PV)-based resource, the minimum ride-through time where
voltage remains below 0.90 per unit is 6.0 s as specified in 7.2.2.1. If the voltage trajectory in Figure D.4 is
applied to this IBR plant, it is required to ride through since the total cumulative time within a 10-sec window
where voltage remains below 0.90 per unit is 4.0 s, less than minimum required ride-through time.
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Associated Transmission Electric Power Systems
Figure D.4—Voltage ride-through requirement, example 4
D.2 Informative figures for voltage ride-through capability requirements
Figure D.5 through Figure D.8 illustrate the voltage ride-through capability requirements specified in 7.2.2.
Figure D.5 and Figure D.6 illustrate the ride-through requirements specified in Table 11, whereas Figure D.7
and Figure D.8 illustrate the ride-through requirements specified in Table 12.
Figure D.5—Voltage ride-through requirements for IBR plants with auxiliary equipment
limitations interconnecting at any nominal voltage except for 500 kV
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Associated Transmission Electric Power Systems
Figure D.6—Voltage ride-through requirements for IBR plants with auxiliary equipment
limitations interconnecting at 500 kV nominal voltage
Figure D.7—Voltage ride-through requirements for IBR plants without auxiliary equipment
limitations interconnecting at any nominal voltage except for 500 kV
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Associated Transmission Electric Power Systems
Figure D.8—Voltage ride-through requirements for IBR plants without auxiliary equipment
limitations interconnecting at 500 kV nominal voltage
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Associated Transmission Electric Power Systems
Annex E
(informative)
Recommended practices for voltage harmonics of inverter-based
resources (IBRs)
E.1 Introduction
Switching action in voltage source converters (VSC) results in a wide range of harmonics. Traditionally
harmonic performance requirements have been limited to the 50th harmonic, resulting in a frequency limit of
2500 Hz for 50 Hz systems and 3000 Hz for 60 Hz systems. In general, the harmonics magnitude of VSC is
smaller compared with the thyristor-based line commutated converters (LCCs), but the generated spectrum
extends to higher frequencies. With new VSC topologies such as modular multilevel converter (MMC), the
generation of the harmonics is expected to be very low, and installation of additional ac harmonic filter banks
may not be necessary from the generating facility point of view. For such topologies the amplification of the
pre-existing harmonics might be dominant and therefore should be considered in the total harmonics
generation.
Harmonic voltage and current distortion at the reference point of applicability (RPA) is not only determined
by the IBR plant, but also by the interaction between the IBR plant and the ac network. For further analysis,
a system representation according to Figure E.1 is used.
Figure E.1—Converter model for total harmonics determination
Both the flow of harmonic current across the RPA and the harmonic voltage at the RPA are functions of not
only the IBR units, but also the impedances and admittances of the balance of plant, the harmonic driving
point impedance of the grid at the point of interconnection (POI), and the background or ambient voltage
distortion present in the grid without the IBR plant.
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Associated Transmission Electric Power Systems
Therefore, for harmonic voltage evaluation at the RPA, the individual aggregated harmonic level is the result
of: (1) harmonic emission (Figure E.2) and (2) amplification or damping of the pre-existing background
voltage harmonics (Figure E.3).
RPA
ZNet(f)
ZPla nt(f)
VPCC_Conv(f)
VConv(f)
Figure E.2—System representation for harmonic emission determination
RPA
ZNet(f)
VNet(f)
ZPla nt(f)
VPCC_Net(f)
Figure E.3—System representation for harmonic amplification or damping determination
Considering the two aspects of the aggregated harmonic levels, the following information should be available
for the full harmonic voltage evaluation:

Network impedance (ZNet)

Background harmonics (VNet)

Plant/converter impedance (ZPlant)

Converter harmonics (VConv)
VSC converters might have capability to compensate low order harmonics. Due to the limitation in
measurement system, control, and hardware setup, the maximum compensation frequency is limited
(approximately 8th order).
To consider different network configurations and system load and generation scenarios (e.g., summer case,
winter case, etc.), the network harmonic impedance can be given as an envelope covering all relevant network
configurations. In practice, it is usually very difficult to determine harmonics above the 50th harmonic order,
so that in many cases the same network harmonic impedance as for the 50th harmonic order is used.
Determination of the network impedance can be done by measurements or by numerical or analytical
calculations (CIGRE TB 468 [B11]; CIGRE TB 766 [B13]). Note that determination of network impedance
using measurements may not provide impedance for all network configurations and that the quality of the
results depends on the quality of input data.
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Background harmonics can be either measured in the network over an extended period to cover different
network topology configurations or can be defined according to the harmonics planning levels. In any case,
the transmission system (TS) owner sets this value.
It is good practice for the TS owner to add margins on the results of network impedance and network
background voltage measurements as they include a level of uncertainty, although unreasonable margins can
lead to unrealistic cases and possibly unnecessary measures such as ac filters. There is no necessary
correlation between worst case network impedance and background harmonic distortion, therefore the
combination of both worst cases may lead to unreasonably high requirements.
Converter impedance and converter harmonics should be provided by IBR manufacturer or aggregated for a
whole plant. The basic principle for impedance and harmonics generation determination is shown in
Figure E.4. ZT and ZR represent transformer and reactors impedances, and CI and CV represent the current
and voltage transfer function, and voltage synthetization stands for modulation techniques (PWM, nearest
level control, etc.) used in the converter.
Figure E.4—Individual converter impedance and harmonics
ZConv in Figure E.1 is the impedance of the IBR or a whole plant as seen from the ac network. In case of a
plant, an aggregation of the harmonic impedances should be done. For the aggregation of the harmonic plant
impedance, not only the harmonic impedances of the IBRs should be considered, but also additional
equipment such as ac cables, filters, etc. Furthermore, the plant topology might change depending on load
and generation scenarios or maintenance schemes.
The plant might consist of IBRs from different manufacturers, so that a third party might be required to do
the aggregation if the IBR manufacturers are not willing to share the impedance values with competitors.
The construct of IEEE Std 519 is based on the assumption that distorting sources are reasonably characterized
as ideal current sources, i.e., the harmonic currents do not change for different grid harmonic impedances. In
the days when IEEE Std 519 was originally developed, line-commutated converters and similar industrial
equipment were the dominant harmonic sources, and these do exhibit reasonably ideal current-source
characteristics. Voltage source converters are characterized as voltage sources behind a complex impedance.
An inverter could be tested against a strong source and have a certain amount of harmonic current flow. The
harmonic current flow if the same inverter is connected to an actual grid can be much greater if the inverter
and the grid are in series resonance or parallel resonance. For example, if the inverter’s Thevenin reactance
is positive (i.e., inductive) and the grid reactance is negative (capacitive) at a particular harmonic frequency
(grid reactance swings between inductive and capacitive at frequencies above a few hundred Hz), the
harmonic current will be increased.
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Harmonic currents cause adverse effects such as equipment overheating. But the harmonic current through
equipment is better indicated by the level of harmonic voltage distortion than by the amount of harmonic
current across the RPA. Unlike the flow of incremental 60 Hz current from an IBR which “fans out” into the
network, harmonic flows are much more complex. The worst-case harmonic current flows through
transformers, etc., are caused by resonant interactions within the transmission grid which tend to greatly
amplify current magnitudes far above the RPA current. These resonances tend to exhibit elevated harmonic
grid impedance seen at the RPA and thus result in elevated harmonic voltage. For example, if harmonic
currents flow out from the RPA to a node where two lines are connected, it is likely that the maximum current
in any one of the lines is greater than the flow from the RPA.
E.2 Harmonic limits
Based on recognized power quality guidelines, such as IEEE Std 519 or IEC TR 61000-3-6:2008 [B42], TS
owner should set objectives on harmonic voltage distortion levels in ac network to reduce potential negative
effects on user and network equipment. Maintaining harmonic voltage levels below such objectives are
mainly a shared responsibility between all users. As explained in E.1, the impact of voltage source converters
on the network harmonic voltage distortion is two-fold. First, VSCs are harmonic-producing devices and
second, IBR plants are likely to amplify (or dampen) pre-existing harmonic voltage levels. Hence, it is
important for IBR plants to limit their resulting aggregated voltage harmonic emission levels.
Since these emission levels greatly depend on the network pre-existing harmonic voltage levels, and the
network harmonic impedance, setting generic limits that could apply in all situations is hardly feasible or
desirable. Ideally, to reduce unduly stringent emission limits, the TS owner should set these limits in an
equitable manner for all users based on the characteristics of the network and pre-existing harmonic voltage
levels. For practical reasons, limits should be set for both effects of IBR plants, as follows:
a)
A limit on the amplification factor (AF) caused by the interaction between the IBR plant and the
network. Based on the nomenclature in Figure E.3, this limit ( AFLim ( f ) ) can be written as:
AFLim ( f ) ≥
Z Plant ( f )
Z Plant ( f ) + Z Net ( f )
(E.1)
where
Z Plant ( f ) is the complex impedance of the plant
Z Net ( f )
is the complex impedance of the network
NOTE—A limit between 1 and 1.5 could be considered for low-order harmonics since in general, low-order
harmonic levels are already high in network. Based on their network characteristic and background harmonic
voltage measurement, the TS owner could relax this limit for some harmonic rank.
d)
A limit on the harmonic emission level of the IBR plant at the RPA (calculated without voltage
harmonic background).
The value of both limits at each harmonic rank should be based on the TS owner’s knowledge of its own
network characteristic and existing or future background harmonic voltage level.
E.3 Verification and adherence evaluation
The verification of the harmonic performance can be done by field measurements. As mentioned before, the
aggregated harmonic performance depends on the network topology (and the resulting network harmonic
impedance) and the pre-existing background harmonic distortion levels. For the harmonic performance
evaluation, field measurements over a period of time are necessary to cover the different network
configurations and background harmonics. In case of harmonic performance violation, it should be verified
that the pre-existing harmonics and the network impedances are within the specified boundaries.
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In many cases the harmonic performance testing period is done by measuring the harmonic performance
during converter operation and directly after plant disconnection, but such measurements cover limited
combinations of converter operating points and network conditions.
IEEE Std 2800 applies to the IBR for as long as the project is interconnected to the transmission system.
Considering the different aspects of aggregated harmonics, it is not reasonable that an IBR facility owner be
solely responsible for either voltage or current harmonics over the plant’s life as changes in the grid are
expected to change both. These changes do not have to be something physically close to the IBR, and do not
have to be changes that would normally be perceived as significant from a 60 Hz standpoint. Large changes
in the grid’s harmonic impedance can result from something as simple as a change in status of a capacitor
bank or a power plant at some considerable distance from the RPA.
Initial harmonic performance evaluations can be performed by a study, for which the steps are:
1)
Determine the range, in the R-X plane, of the transmission system harmonic impedances. This
requires modeling the transmission system for a considerable distance 189 from the RPA and
considering the various permutations of relevant transmission components (e.g., generators
online or offline, transmission line outages, capacitor bank status, etc.).
2)
Determine the pre-existing background voltage harmonics at the RPA.
3)
Manufacturer to determine the Thevenin model for the IBR units for each harmonic. This may
change with operating point. As indicated in the diagram, the Thevenin impedance of the
inverters is substantially affected by the controls, particularly at the lower-order harmonics. The
source characterization can be made by testing of units and/or detailed converter modeling. For
very large inverters, only the latter is feasible.
4)
Model the balance of plant (BoP) (e.g., cables, filters, etc.).
5)
Perform analyses of harmonic performance for the range of operating conditions and status of
inverter units and BoP components such as capacitor banks.
Once the plant is in commercial operation, the IBR owner should only be responsible for ensuring that the
harmonic characteristics of the plant are maintained within the ranges of values considered in the initial study.
If this is true, then any variations in performance can be assumed to be caused by the transmission grid. The
system operator may require on-site testing and measurement to verify the data and the hypothesis used in
the study (e.g., the harmonic impedance of the installation).
189
See CIGRE TB 766 [B13]. Chapter 5.3, Considerations for Power System Representation.
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Annex F
(informative)
Guidance on setting protection with inverter-based resources (IBRs)
F.1 Frequency protection
Faults and abnormal system conditions produce frequency transients that may cause relays to make unreliable
decisions. The IBR unit and IBR plant (generally referred to as IBR throughout this annex) control system
should not use instantaneous measurement within the protection algorithm. The use of time-delay relaying
or filtering increases the security of the frequency protection scheme. An IBR should use filtered or timedelayed operating quantities for its protection algorithm. The IBR control system may derive frequency from
a voltage, current, or speed measurement. IEC 60255-181 may specify sufficient functional requirements for
frequency protection to comply with this standard.
If the IBR does not have an off-nominal frequency limitation, then an IBR owner should not implement
frequency protection for tripping. Unlike wind turbines, photovoltaic (PV) and battery energy storage
systems do not have the traditional electromechanical limitations associated with generator protection.
Essential auxiliary equipment frequency protection should also comply with the frequency ride-through
requirements of the IBR plant.
Frequency protection for IBR collector system feeders and main IBR transformer should only be
implemented if the associated equipment has an off-nominal frequency limitation. If there are no abnormal
frequency limitations for equipment beyond the IBR unit terminals (point of connection [POC]), then an IBR
owner should not implement frequency protection for any equipment beyond the terminals of the IBR unit.
If an equipment capability limitation is identified within these zones of protection, then an IBR owner may
implement frequency protection.
F.2 Rate of change of frequency (ROCOF) protection
Transients on the grid may cause ROCOF-based protection to actuate and trip an IBR unnecessarily. The
IBR is expected to ride through these transient conditions and support the grid. The use of this scheme may
reduce the reliability of the resource and may negatively impact the ride-through capability performance.
F.3 AC voltage protection
The IBR may be allowed to provide as much voltage support as possible. The protection scheme should not
restrict the IBR from providing voltage support to the grid. This should help ensure that the grid receives as
much voltage support as possible from the individual resource.
An IBR may use either filtered (fundamental-frequency) and/or time-delayed operating quantities, wherever
possible, for its protection algorithm to reduce vulnerability of misoperation during voltage and switching
transients. If a time-delayed operating quantity is used, the IBR unit manufacturer should verify that the delay
does not inhibit protection from equipment damage. Total operating time for the voltage protection scheme
should be coordinated with the IBR capability for the entire range of voltage magnitudes. IEC 60255-127
may specify sufficient functional requirements for over-/undervoltage protection to comply with this
standard.
The voltage drop across the collector system may be accounted for in the coordination of voltage protection
schemes. Also, this protection scheme may not prohibit the resource’s ability to provide voltage support to
the grid. Hence, feeder protection on the collector system may not trip prematurely for voltage excursions
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that the IBR is capable of riding through, unless it is required to clear faults internal to the IBR plant. This
should help ensure coordination between the point of measurement (POM) and the IBR.
Any overvoltage and overexcitation protection within the IBR plant may be coordinated with overvoltage
and overexcitation capability of various equipment within the IBR plant. The protection characteristic may
coordinate with the overexcitation capability curve of the IBR plant and IBR unit(s) transformers.
The protection may coordinate with the equipment rating limitation, associated with the high-voltage system,
and the voltage control system of the plant controller. If there are no equipment capability limitations, then
voltage protection at the POM is not required.
F.4 AC overcurrent protection
Phase overcurrent protection for an IBR should be developed based on the IBR’s capability to provide current
during short-circuit conditions without damage to the IBR equipment. The set points for this scheme should
take into account the maximum current support the resource can provide to the system. This should consist
of the active and reactive current components generated by the IBR. This should help ensure that the grid
receives as much voltage (reactive current) and frequency (active current) support as possible from the
individual resource.
An IBR should use either filtered (fundamental-frequency) or time-delayed operating quantities wherever
possible, for their protection algorithm to reduce nuisance tripping due to system transients. If a time-delayed
operating quantity is used, the IBR unit manufacturer should verify that the delay does not inhibit protection
from equipment damage. In addition, the time delay should coordinate with the protection scheme on the
transmission system. IEC 60255-151 may specify sufficient functional requirements for over-/undercurrent
protection to comply with this standard.
In the IBR plant, overcurrent protection for various facility transformers should coordinate with the thermal
capability curve (e.g., damage curve) of the equipment. This includes both the electrical and mechanical portions
of the curve. The scheme should coordinate with both the upstream and downstream protection schemes. This
scheme should not artificially constrain the total current (active and reactive) output of the resource.
To reduce the risk of nuisance tripping, feeder protection on the collector system should not artificially
constrain the total current support of the IBRs connected to it. The scheme should account for the maximum
load/support current from the aggregate of the IBRs connected to the feeder with a margin.
Phase overcurrent protection for the main IBR transformer and POM/reference point of applicability (RPA)
should consider the additional current support from reactive compensating devices on the collector system
bus. These devices provide VAR support (reactive current) to the grid during system voltage excursions and
abnormalities. That additional current should flow through the collector system bus and main IBR transformer
into the transmission system. This element should also coordinate with the upstream phase protection scheme
(e.g., phase distance protection, other phase overcurrent elements, etc.) to allow that scheme an opportunity
to isolate an abnormality.
F.5 Unintentional islanding protection
Unintended islands can form between the transmission system (TS) source and the IBR plant either from a
fault (such as a bus fault) that isolates a tie line or inadvertent switching. In cases where such an island is not
intended to operate, it may subject connected equipment and customers to abnormal voltage and frequency,
resulting in possible damage. Furthermore, the protective relay settings within the island may not be set for
the available fault duty and may not provide adequate protection resulting in potential equipment and safety
issues. Automatic reclosing is also a concern since reclosing into an island, when not in synchronism, may
result in equipment damage and a transient on the system. Many IBR units are equipped with active
unintentional islanding protection schemes, however this may be disabled for ride-through concerns. Any
active unintentional island detection schemes are recommended to be disabled for IBRs in the scope of this
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standard unless it is required to protect the IBR; communication-based island detection schemes are preferred,
if needed. With agreement of the TS owner, active unintentional islanding detection may be allowed if it
meets the ride-through requirements. A communication medium may be utilized as a primary means to
implement this function.
External methods may be employed, such as direct transfer trip (DTT), in which the conditions that forms
the island are monitored and should send a trip to the IBR plant when actuated. The DTT transmit points can
be initiated via a combination of breaker status and relay tripping. The remote breaker status may be
transmitted to the IBR plant. The protection associated with the interconnection system may configure this
received signal(s) to initiate a trip of the IBR plant interconnecting breaker during island conditions. DTT
may be transmitted to the breaker at the POM on the high-side of the main IBR transformer, collector system
feeder breaker, or individual IBR unit breakers.
F.6 Interconnection system protection
The interconnection system consists of elements between the main IBR transformer and the connection with
transmission system. The interconnection facility consists of elements that connect a main IBR transformer
to the transmission system that are used exclusively to export energy directly from an IBR plant. Protection
systems for transmission-level interconnections may be located at the high-side of the main IBR transformer,
POM, or tie line. This protection system should have sufficient infrastructure to reliably protect the
interconnection system from all possible abnormalities. This includes all fault scenarios between the main
IBR transformer and the TS. Abnormalities beyond the interconnection system (e.g., within the
transmission/sub-transmission network, beyond the remote TS bus, etc.) are not required for this protection
scheme to cover.
There are several application considerations when protecting the interconnection system (Hooshyar, Azzouz,
and El-Saadany [B28], IEEE PES-TR81 [B48], IEEE PES-TR68 [B46], Nagpal and Henville [B71],
Chowdhury and Fischer Part I [B9], Chowdhury and Fischer Part II [B10], Sandia Report [B104]):

Primary protection may include application of an underreaching distance zone and a communicationassisted protection scheme (e.g., line current differential, permissive overreaching transfer trip, etc.)
with the infrastructure including a communication medium (e.g., fiber, power line carrier, etc.).

The underreaching distance zone should be secure, it should not overreach the remote TS bus. The
underreaching elements should be reliable and their settings consider the IBR response time and
behavior during the fault.

A communication-assisted protection scheme increases protection system dependability and may be
used to meet critical clearing time requirements to support grid stability.

The control system of an IBR may need some response time to exhibit behavior that is expected by
protection elements such as the directional, fault-type identification, and distance (Hooshyar,
Azzouz, and El-Saadany [B28], IEEE PES-TR81 [B48], IEEE PES-TR68 [B46], Nagpal and
Henville [B71], Chowdhury and Fischer Part I [B9], Sandia Report [B104]). Use of supervisory
overcurrent thresholds and time-delays may improve protection system security and dependability
(IEEE PES-TR81 [B48], Nagpal and Henville [B71], Chowdhury and Fischer Part II [B10]).

Backup protection may include application of time-delayed step-distance zones, zero-sequence
overcurrent elements and undervoltage elements (IEEE PES-TR81 [B48], Nagpal and Henville
[B71], Chowdhury and Fischer Part II [B10]). Backup protection facilitates time-delayed fault
clearing when the primary protection schemes are unable to clear a fault, for instance due to a failure
of the communication channel.
The protection system should be coordinated with the TS owner. There should be a point of electrical
disconnection (e.g., circuit breaker) in between the main IBR transformer and TS. This should allow the
protection system to isolate the IBR plant from transmission abnormalities and isolate the transmission system
from any IBR plant abnormalities. The interconnection system should include an adequate level of auxiliary
equipment (e.g., CTs, PTs, etc.) for secure and dependable protection. This level of auxiliary equipment
should be defined by the TS owner.
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Annex G
(informative)
Recommendation for modeling data
G.1 General
The list below pertains to an existing inverter-based resource (IBR) plant where all such data exists and what
is being requested is as-built data. In the case of planning studies related to an IBR plant to be built in the
future, it is understood that some of these details only becomes available once the IBR plant is built or closer
to being commissioned, and thus an iterative process of studies is required as the data gets closer to the asbuilt information.
G.2 Steady-state modeling data requirements
In order to model the IBR plant for steady-state analysis, the following data are needed:
a)
One-line electrical drawing of the entire collector system for the IBR plant showing:
1)
All feeder cables and overhead lines and their lengths and line parameters (i.e., ohms resistive
per unit length, ohms reactive per unit length, and micro-farads per unit length)
2)
The position of each IBR unit on each feeder including the type, vendor, and model of each
IBR unit
3)
The substation transformer at the point of measurement (POM) and how the IBR plant ties to
the transmission system (TS)
4)
Any other equipment at the substation at or behind the point of measurement, e.g.:
5)
i)
Mechanically-switched shunt capacitors (or reactors), if any, and the number and size, and
location of such switched-shunt capacitors (or reactors), including any stand-by filter
banks
ii)
Dynamic reactive devices (static var compensator [SVC], static synchronous compensator
[STATCOM], or synchronous condenser), if any, and their nameplate rating, and exact
location in the collector system
If there exists any significant auxiliary load (i.e., exceeding 1% to 2% of the nameplate rating
of the plant) in the plant, the location and amount of such loads should also be shown on the
one-line.
6) Note: Although not necessary for power flow and positive-sequence stability studies, the
location and data pertaining to any grounding transformers should also be shown on the oneline electrical drawing of the collector system, as may be needed for short-circuit and protection
studies.
b)
Line parameters for any radial transmission line between the point of interconnection (POI) and the
high-side of the substation transformer that is owned and operated by the IBR owner.
c)
Information on the substation transformer at the point of measurement, namely:
1)
Nameplate data:
i)
Leakage reactance (or nameplate impedance) and MVA base
ii)
Winding ratio (primary voltage and secondary voltage rating)
iii)
X/R ratio
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d)
e)
Winding connections (Y-grd/Delta, etc.)
v)
Number and size of fixed tap positions
vi)
Transformer cooling type and ONAN/ONAF/OFAF ratings
2)
Actual fix-tap position setting of the transformer in the field
3)
If the transformer has an on-load tap changer (OLTC), then the following information is needed:
i)
Number of taps (e.g., 32, 16 up, and 16 down)
ii)
Tap size (e.g., 0.625%)
iii)
Which side is being regulated (e.g., controlling low-voltage side to keep voltage between
102% and 100% of nominal)
iv)
Tap timing (e.g., first tap moves after voltage is outside of the band for 30 s, and
subsequent tap movements are once every 5 s, until voltage comes back within the control
band)
IBR unit original equipment manufacturer (OEM) data:
1)
The type, model, manufacturer, control firmware version as applicable, and year of manufacture
for each type of IBR unit in the IBR plant (e.g., GE SLE 1.5 MW units built in 2001, SMA
photovoltaic (PV) inverter model 1850, etc.)
2)
Number of IBR units in the plant
3)
Nameplate ratings of the IBR unit (kV, MW, MVA, etc.)
4)
The individual IBR units reactive capability curve provided at different ambient temperatures
(e.g., 25 °C, 35 °C, 45 °C, etc.)
5)
IBR units de-rate curves based on temperature and elevation
IBR unit transformer data:
1)
f)
iv)
These are the individual, e.g., pad mount transformers, that transform the low-voltage output of
the individual IBR units up to the medium-voltage level of the collector system. The nameplate
data needed is:
i)
Leakage reactance and MVA base
ii)
Winding ratio (primary voltage and secondary voltage rating)
iii)
X/R ratio
iv)
Winding connections (e.g., Y-grd/Delta)
v)
Fixed tap position (typically nominal taps)
For energy storage systems, the total energy capacity (MVAh), the maximum allowable
charge/discharge rate, and the maximum/minimum absolute value of state of charge.
The above data can be used to develop an equivalent collector system model for power flow analysis based
on either the NREL method (Muljadi et al. [B70]) or the ERCOT (Cheng et al. [B7]) approach, or any other
documented and technically reasonable methodology.
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Associated Transmission Electric Power Systems
G.3 Stability analysis dynamic modeling data requirements
In order to model the IBR plant in a time-domain stability program 190 the following data are needed:
a)
OEM provided low/high voltage and low/high frequency ride-through capabilities of the IBR units.
b)
OEM provided parameters for the latest available generic models that are available as standard
models in commercially available planning software tools at the time of IBR plant commissioning
(e.g., at the time of writing this document the so-called second generation generic WECC models 191
or the IEC 192 generic models). In cases where the latest generic models do not adequately represent
the IBR plant for a given intended use, an explanation should be provided of the shortcomings of the
generic models for the intended use, and the recommended models and their parameters to be used
instead.
c)
If requested by transmission system (TS) owner or TS operator, OEM user-written model, parameters
and documentation. Documentation may include user manual, user test case(s) example(s), specialcase instructions, any limitations, etc.
G.3.1 Components
The components that should be included are:
a)
The generator/converter model
b)
The electrical controls model (for each individual IBR unit)
c)
The overall plant-level controller model (note that the plant controller may often be provided by a
different vendor than the vendor of the IBR unit, thus the models for the individual IBR unit and the
plant controller may come from two different vendors)
d)
For wind-turbine generators, depending on the technology, and if relevant for electrical performance,
the appropriate mechanical-side models (e.g., drive-train, aero-dynamic, pitch-controller, and torquecontroller models)
e)
Models and settings for the low/high voltage and frequency ride-through characteristics of the IBR
units as implemented on site and verified by factory type tests.
G.3.2 OEM user-written dynamic models
If an OEM user-written dynamic model, and parameters, are provided, then it should be accompanied with:
a)
Good documentation to allow the user to properly initialize and run the model
b)
A list of all the model parameters 193
190
Ttime-domain stability program is a type of software tool that use phasor (fundamental-frequency) domain analysis, which are
typically positive-sequence (fundamental-frequency) stability tools.
191
The latest WECC second generation models, as of today, are documented on the WECC MVWG website
(https://www.wecc.org/RAC/Pages/MVWG.aspx) as well as in the user’s manual of the major commercial power system simulation
software platforms. These models continue to be augmented with new modules and functionality as modeling practices improve and as
the technology constantly changes. Thus, the parameters for the latest models should be provided at the time the plant is built. As of
2018, the latest WECC models are also described in: Pourbeik, P., Sanchez-Gasca, J., Senthil, J., Weber, J., Zadehkhost, P., Kazachkov,
Y., Tacke, S., and Wen, J., “Generic Dynamic Models for Modeling Wind Power Plants and other Renewable Technologies in Large
Scale Power System Studies,” IEEE Transactions on Energy Conversion, vol. 32, no. 3, pp. 1108–1116, Sep. 2017.
A user’s guide for these second generation generic models is also available: EPRI, Model User Guide for Generic Renewable Energy
System Models, 13 Jul. 2018, https://www.epri.com/#/pages/product/3002014083/.
192
The IEC models, as of July 2019, have not yet been fully finalized and approved and do not yet exist in the North American–based
commercial software platforms. The IEC standard models are being developed by IEC TC88 WG27. They are similar to the WECC
models, but do have some significant differences.
193
Ideally, parameters that user can tune/change within a range should be documented.
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Associated Transmission Electric Power Systems
c)
A block-diagram 194 explaining the functionality of the model
d)
An explanation of how to perform the following tests in the model:
1)
Changing the voltage (or reactive power, or power factor) reference of both the plant-level
controller and an individual IBR unit, for effecting a voltage/Q reference step test.
2)
Changing the frequency reference of the plant controller to effect a frequency reference step
test. For isolated IBR interconnected to the ac transmission system via voltage source converter
high-voltage direct current (VSC-HVDC) system, the frequency reference change for testing of
isolated IBR model is associated with the ac-dc converter station providing ac source to isolated
IBR and is not applicable to the converter station connected to the ac transmission system.
3)
Changing the plant-level active power reference step point to effect a step change in the plant’s
active power output.
G.3.3 SVC or STATCOM
If there is an SVC or STATCOM in the plant, then provide the following:
a)
Year built, size, rating, and manufacturer
b)
Parameters for a standard model (e.g., SVSMO1, SVSMO2 or SVSMO3 models; see Pourbeik et al.
[B101]) or OEM provided user-written model of the SVC/STATCOM. For a user-written model,
clear documentation is needed to list all parameters and parameter values, and block-diagrams to
explain the model functionality.
NOTE—It should be understood that although the generic models are public and their structures well understood, detailed
user-written vendor-specific models are typically considered proprietary information and thus may be provided by an
OEM under a non-disclosure agreement. In such cases, the OEM should also provide the parameters of the generic
(public) models, with a brief description of the limitations of the generic models, so that the utility is able to share the
generic models with neighboring entities and/or reliability entities that may require them for system-wide studies.
G.4 Electromagnetic transient (EMT) dynamic modeling data requirements
Along with positive-sequence stability models, EMT models may be needed to study certain issues involving
inverter-based resources that cannot be studied in positive-sequence stability programs. These types of
studies are particularly useful in areas where inverter-based resources may interact with other power
electronic controls, such as existing HVDC, STATCOMs, SVCs, or other inverter-based resources. They are
also useful where inverter-based resources are connected in low short-circuit strength networks, or in close
proximity to series capacitors. Therefore, TS operator/TS owner should specify requirements for inverterbased resources to provide EMT models in situations where an EMT-type study may be needed now or in
the foreseeable future. All OEMs are encouraged to develop such EMT models for their equipment, so that
such models are available when requested.
The TS operator/TS owner may either require EMT models for all newly interconnecting inverter-based
resources or may require these models on a case-by-case basis. Situations where these models should be
required may include, but are not limited to, the following:

Areas of low (or decreasing) short-circuit strength (NERC Reliability Guideline [B77])

Areas near existing (or planned future) series-compensated transmission circuits, presenting a risk of
subsynchronous resonance phenomena (e.g., subsynchronous oscillations [SSO], subsynchronous
control interaction [SSCI], self-excitation, etc.), as well as other resonance issues and a risk of high
transient overvoltages
194
OEMs may consider block diagrams for user-written dynamic models as proprietary information. The OEM may require nondisclosure agreement before sharing proprietary block diagrams. The end user should not use block diagrams to debug the model. In
some cases, block diagram for user-written dynamic models may not be available.
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Associated Transmission Electric Power Systems

The addition of new inverter-based resources in areas with existing or planned high concentration of
inverter-based resources, where situations of control interactions, control mode cycling, or other
control instabilities may occur

Interconnections of inverter-based resources near HVDC transmission systems and other large
transmission-connected reactive devices that are interfaced through power electronics (e.g., FACTS
devices)
Detailed EMT modeling requirements may be developed by TS operator/TS owner to help ensure consistent
EMT models are provided, based on the type of study being performed and the specific EMT simulation tools
being used. In general, the EMT model should adhere to the following requirements (PSCAD Model
Requirements Rev. 9 [B102]), although TS operator/TS owner may have additional requirements for their
needs.
G.4.1 Model accuracy features
The EMT model should have sufficient detail to represent:

The full detailed inner control loops of the power electronics, as implemented in the actual equipment
to be installed. Most IBR unit manufacturers can provide models that embed the actual firmware
code into the EMT model, and this is the recommended type of model to be supplied for EMT
studies. 195 Depending on scope of the EMT study, TS operator/TS owner may request discrete switch
model or averaged switch model for inverters (CIGRE TB 727 [B14]).

All pertinent control features (e.g., external voltage controllers, plant-level controllers, phase-locked
loops). This includes the actual (or expected) operating modes and settings required for systemspecific installations, tuned to the expected or as-built controls settings. IBR unit-level and plantlevel 196 controls should be modeled appropriately, with actual hardware code preferred.

All pertinent electrical and mechanical configurations. These may include, but are not limited to:
filters, specialized transformers, and mechanical systems that could impact electrical performance
such as drivetrain controls and pitch controls.

All pertinent inverter-based resource protection systems relevant to performance that are modeled in
detail for both balanced and unbalanced fault conditions. Typically, this includes, but is not limited
to, ac over- and undervoltage protection (instantaneous phase and RMS), over- and under-frequency
protection, dc bus over- and undervoltage protection, and IBR unit overcurrent protection. Actual
firmware code is recommended to be implemented in the model for these features.
G.4.2 Model usability features
The EMT model should meet usability criteria to help ensure study engineers have a functional model,
including the following:
195
This refers to “black box models” of the exact controls code (e.g., C code) used in the actual controls firmware. The controller source
code for all relevant controls is typically compiled into binary DLLs to protect the intellectual property of the manufacturer. If real code
models are not used, or if key control features are approximated using generic representations, additional validation may be required. A
three-phase sinusoidal source representation should not be used. Models should not be manually translated block-by-block from control
block diagrams due to inaccuracies that may be introduced during this translation (e.g., in the electrical network and interface to the
controls, or portions of the controls such as PLL circuits or protection circuits).
196
Often, the plant-level controls also include the control of other reactive devices, such as shunt capacitor banks and STATCOMs
within the plant. The plant-level controls modeling may include the control and coordination of other devices as well, if those devices
would operate in the time frame of the study.
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Associated Transmission Electric Power Systems

The model should have control or hardware options accessible to the user that are pertinent to the
study (e.g., active current/power ramp rates). Diagnostic flags (e.g., control mode or protection
system activation) should also be accessible. 197

If the simulation time step is very small, or if a very specific time-step is required by the model, this
can lead to very slow simulation times and incompatibilities with other models. The model should
not be restricted to operating at a single time step, but should be able to operate within a range (e.g.,
10 μs to 20 μs). 198
NOTE—Larger integration time steps mean that the entire model (i.e., equipment plus network) is not adequate
for assessing fast front-switching transients on the system.

The model should include a user manual or guide, and a sample implementation test case. Access to
technical support engineers is desirable.

The model documentation should provide a clear way to identify the specific settings and equipment
configuration to be used in any study, such that during commissioning the settings used in the studies
can be checked. This may be control revision codes, settings files, or a combination of these and
other identification measures.

The model should accept external reference variables. Examples include active and reactive power
ordered values for reactive control modes, and voltage reference and droop values as applicable for
voltage control modes. Model should accept these reference variables for initialization, and be
capable of changing these reference variables mid-simulation (i.e., dynamic signal references).

The model should be capable of ramping up to a steady-state equilibrium point by itself. Once
provided with initial condition variables, the model should initialize and ramp to the ordered output
without external input from simulation engineers. Any slower control functions that are included
(such as switched shunt controllers) should also accept initial condition variables if required.

The model should have the ability to scale plant capacity to the extent possible within EMT program’s
electrical components limitations. The plant active power capacity of the model should be scalable
in some way, either internally or through an external scaling transformer or power amplifier. This is
distinct from a dispatchable power order, and is used for modeling different capacities of the plant or
breaking a lumped equivalent plant into smaller composite models.

The model should have the ability to dispatch its output to values less than nameplate. This is distinct
from scaling a plant from one unit to more than one, and is used for testing plant behavior at various
operating points.
G.4.3 Model efficiency features

The EMT model should also meet the following requirements to help ensure studies can be completed
effectively: During the simulation initialization period, model should reach a steady-state equilibrium
point as quickly as possible (e.g., less than 5 s) to user-supplied terminal conditions.

The model needs to support multiple instances of itself in the same simulation.
197
Care should be taken to confirm that any user-settable options are not changed in a way that is not implementable in the real hardware,
and that any selectable options are actually available at the specific site being considered. Discussion with the manufacturer is
recommended prior to any changes being made in model configuration.
198
Most of the time, requiring a smaller time step means that the control implementation has not used the interpolation features of the
software, or is using inappropriate interfacing between the model and the larger network. Lack of interpolation support introduces
inaccuracies into the model at higher time steps. For example, the model should be capable of running accurately with a time step greater
than 20 microseconds, or greater than 10 microseconds if required by specific control parameters.
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Associated Transmission Electric Power Systems
G.5 Power quality, flicker, and rapid voltage change (RVC) modeling data
requirements
In addition to ones already identified in the preceding sections, the following data are needed:
For IBR harmonic characterization (i.e., harmonic spectrum), Thevenin or Norton equivalent source
representation of inverters at each integer harmonic order from 2 to 50, plus each non-integer harmonic
(interharmonic) that is produced. The TS owner may also request frequency-dependent impedances of various
components of within the IBR plant.
For both, main step-up transformer at the POM and individual IBR unit transformers:

Air core inductance

Air-core flux intercept

No load test results: current and losses at 90%, 100%, and 110% of the rated voltage
G.6 Short-circuit modeling data requirements
In addition to ones already identified in the preceding sections, the following data are needed:
199

IBR plant ground grid design data for use with lightning, insulation, short-circuit, and protection
system coordination studies.

Radial transmission line between the POI and the high-side of the substation transformer that is
owned and operated by the generation owner: At a minimum, the lumped positive and zero sequence
impedances and shunt susceptances of the line. Necessary data may also include, but is not limited
to, the following: tower configuration with conductor spacings relative to each conductor and ground,
insulator string length (for calculation of flash-over arc impedance), conductor type (including static),
and line length (in feet). If the conductor is a special type, the complete electrical specifications for
the conductor should be provided (i.e., ac resistance, conductor radius, conductor GMR, etc.).

Substation transformer: Transformer type, winding configuration, and manufacturer’s test report.
Data for this transformer should include zero sequence impedance information. If applicable, data
for any resistive or reactive neutral grounding element.

Collector system one-line diagram showing the full topology (with cable/line lengths) between
turbines/inverters and other elements, and sequence resistance and reactance values. The information
should also include any shunt compensation within the plant, including nameplate information for
those devices. Equivalent representations may be allowable, and details should be provided on where
equivalencing can be used.

The short-circuit model of the IBR unit based on recommendation from the IEEE PSRCC WG C24
(IEEE PES-TR78 [B47]) or subsequent short-circuit modeling references. 199
The short-circuit models for IBRs continue to improve, hence, should be based on latest industry developed references.
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Associated Transmission Electric Power Systems
Annex H
(informative)
Data that transmission system (TS) owner and TS operator may provide to
the inverter-based resource (IBR) developer
To the extent possible and upon request from the IBR developer, the TS owner/TS operator should provide
the following data to the IBR developer to properly design the IBR plant to physically connect to the TS and
for the expected TS operating conditions. In addition to ones already identified in the following sections, the
IBR developer may request additional necessary data for the IBR plant design from the TS owner/TS operator.
H.1 System data
Note that some shared information may not be available from the TS owner or TS operator upon initiation of
the IBR plant design because the TS owner may complete analysis and design of the TS modifications
required for the interconnection, including the point of interconnection (POI) substation and the protection
system upgrades required in the TS facilities. The information may be shared, as needed, once it is available.
H.1.1 System diagrams and point of interconnection substation information
The TS owner may provide the IBR developer with diagrams and technical information depicting the area TS
system as necessary for design of the IBR interconnection system with the TS. Such information may be
limited to information deemed applicable and sharable by the TS owner and TS operator.
The IBR developer may receive, from the TS owner, interconnection system design requirements related to
the POI substation once they become available in the interconnection process.
H.1.2 Voltage data
The IBR developer may receive the following voltage data for the proposed POI from the TS owner: nominal
operating voltage, typical operating voltage range, maximum contingency voltage, minimum contingency
voltage, transient voltages, 200 maximum negative sequence voltage (performance), and maximum negative
sequence voltage (rating).
H.1.3 Insulation levels
The IBR developer may receive the following insulation levels for the proposed POI substation from the TS
owner:
200

Basic insulation level (BIL)

Switching impluse level (SIL)

Lightning impulse protective level (LIPL)

Switching impulse protective level (SIPL)

Power-frequency withstand voltage
If necessary, more transient voltages can be included, refer to Figure B.2 from IEEE Std 1031™-2011.
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H.1.4 Frequency requirements
The IBR developer may receive frequency requirements from the TS operator and load balancing entity as
needed for ride-through and normal operation settings, which may include: nominal frequency, maximum
continuous frequency, minimum continuous frequency, maximum frequency, and minimum frequency. The
TS owner may share under-frequency load shedding scheme settings if deemed necessary and sharable.
H.1.5 Protection system design details
The IBR developer may collaborate with the TS owner to determine the design specifications of all protection
systems associated with the IBR plant at the POI. The TS owner may also provide to the IBR developer the
TS protection system settings as needed for coordination between the IBR plant’s internal protection systems
and the TS protection system.
H.1.6 Short circuit levels
The IBR developer may receive the following short-circuit data from the TS owner for both present and the
foreseeable future (planning horizon) for the POI, along with the analysis method and relevant assumptions:

Maximum three-phase and single-line-to-ground fault current, including X/R ratio

Minimum three-phase and single-line-to-ground fault current, including X/R ratio (considering
various operational scenarios and/or contingencies)
NOTE—It is important that the short-circuit levels are based on a realistic assessment of grid operating conditions. Shortcircuit analysis performed to determine maximum short-circuit currents, such as to determine circuit breaker ratings,
typically models all generation in service. Operating conditions, particularly during light load conditions and where
synchronous generation is displaced from commitment schedules by IBR, often will have far less synchronous generation
connected and thus much lower short-circuit levels.
H.1.7 Environmental conditions
If available, the TS owner may provide to the IBR developer some environmental condition information
including, but not limited to: altitude above sea level, maximum ambient temperature, maximum daily
average ambient temperature, maximum monthly average ambient temperature, maximum yearly average
ambient temperature, average temperature of the hottest month, minimum ambient temperature, minimum
daily average ambient temperature, minimum monthly average ambient temperature, minimum yearly
average ambient temperature, pollution level (according to IEC 60815), seismic qualification level, humidity,
ground resistivity, wind gust factor or maximum wind gust, ice loading conditions (thickness), and maximum
ground snow depth. This information may also be available from other sources.
H.1.8 Transmission system harmonic data
IBR developer may receive, from the TS owner, ranges of transmission system driving point impedances
(resistive and reactive) at the POI as a function of frequency or harmonic order. These impedance ranges are
obtained by system modeling, considering a wide range of operating conditions, configurations, and
contingencies.
The IBR developer may receive, from the TS owner, the background voltage distortion data at the POI, if the
POI already exists, or otherwise at the closest existing substation to the proposed POI.
The background voltage distortion data may include integer harmonics up to 50th order plus each non-integer
harmonic (inter-harmonic) as measured at the POI (CIGRE TB 754 [B15]). The data may be measured
through a period of time, long enough to capture seasonal changes in the grid loading and generation
conditions.
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Alternately, TS owner may provide voltage harmonics distortion data at the POI based on their system model.
The TS owner may consider sharing the model with IBR developer for updating the model during the IBR
project execution for future use.
H.2 Interconnection ratings
The IBR developer initially requests an interconnection with the TS owner at a designated POI and provides
a requested value for the IBR continuous rating (ICR) and, if applicable, the IBR short-term rating (ISR).
The TS owner, in concert with the TS operator and the regional reliability coordinator, will perform studies
to determine what transmission system upgrades, if any, are required to connect the IBR plant to the TS and
to deliver power from the IBR plant to the recipient. Those studies will also determine the technical and
operational requirements for the IBR plant. These ratings will also be registered with the TS operator or the
authority governing interconnection requirements (AGIR). For IBR with energy storage systems (ESSs), the
IBR owner may also register the IBR continuous absorption rating (ICAR).
Obtaining commercial capacity on the TS to deliver power from the IBR plant to the intended recipient is a
separate process and usually requires separate studies and commercial agreements not addressed in this
standard.
H.2.1 Transmission system operation limits
The TS owner, TS, operator, and the regional reliability coordinator may disclose if there are transmission
system operating limits (SOLs) and/or interconnection operating limits that may impact the ability of the IBR
plant to inject or receive power at the POI under specific system conditions.
H.2.2 IBR continuous rating (ICR)
The TS owner, in concert with the TS operator and the regional reliability coordinator, should study and
determine the steady-state, continuous active power rating of the IBR plant or hybrid IBR plant to be
registered by the IBR owner at the TS operator’s or AGIR’s registry. This rating may be included in the
interconnection agreement between the TS owner and the IBR owner.
H.2.3 IBR continuous absorption rating (ICAR)
For IBR plants with energy storage systems (ESSs), the TS owner, in concert with the TS operator and the
regional reliability coordinator, should study and determine the IBR continuous absorption rating of an IBR
plant or hybrid IBR plant registered by the IBR owner at the TS operator’s or AGIR’s registry. This rating
may be included in the interconnection agreement between the TS owner and the IBR owner.
H.2.4 IBR short-term rating (ISR)
The TS owner, in concert with the TS operator and the regional reliability coordinator, should study and
determine the temporary, short-term active power rating of an IBR plant or hybrid IBR plant registered by
the IBR owner at the TS operator’s or AGIR’s registry. This rating may be included in the interconnection
agreement between the TS owner and the IBR owner.
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Associated Transmission Electric Power Systems
Annex I
(informative)
Illustration of voltage ride-through performance requirements
This informative annex provides an example to illustrate voltage ride-through performance requirements
specified in 7.2.2.3.5. This example assumes an inverter-based resource (IBR) plant consisting of type IV
wind turbine generators. During mandatory operation region, wind turbine generators are configured to
operate in a reactive current priority mode. To illustrate performance requirements, a three-phase fault is
applied on the transmission system (TS) network at time T = 3 s. As a result, voltage at high-side terminals
of main IBR transformer point of measurement (POM) of the IBR plant drops to 50%. Figure I.1 and
Figure I.2 show instantaneous and positive-sequence phasor voltages at the POM, respectively. The phasor
quantities are derived using a one-cycle filter. As such, the instantaneous voltage drops upon inception of a
fault, however, the positive-sequence phasor voltage takes 16.66 ms (for a 60 Hz system) to transition from
pre-fault voltage. Figure I.3 and Figure I.4 show instantaneous and positive-sequence phasor voltages at the
terminals of the wind turbine generator, respectively. Finally, Figure I.5 and Figure I.6 show instantaneous
and positive-sequence phasor currents on terminals of the wind turbine generator, respectively. As noticed in
Figure I.6, the reactive current injection before the fault is zero. The reactive current rises upon inception of
a fault and reaches 90% of the final steady-state value within 40 ms. The incremental reactive current (∆IR1), i.e., difference between pre-fault and during fault reactive current output, is 60%. The settling time is
approximately 60 ms. In this example, the wind turbine generator (WTG) employs a proportional control for
closed loop voltage control, hence, reactive current does not increase to maximum current rating per
definition of reactive current priority mode to regulate voltage.
400
V_PhaseA
V_PhaseB
V_PhaseC
300
Voltage (kV)
200
100
0
-100
-200
-300
-400
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.1—POM instantaneous voltage
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1.2
Voltage (per unit)
1
0.8
0.6
0.4
0.2
0
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.2—POM RMS voltage
0.8
PhaseA
PhaseC
PhaseB
0.6
Voltage (kV)
0.4
0.2
0
-0.2
-0.4
-0.6
-0.8
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.3—WTG instantaneous voltage
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1.2
Voltage (per unit)
1
0.8
0.6
0.4
0.2
0
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.4—WTG terminal RMS voltage
6
PhaseA
PhaseB
PhaseC
4
Current (kAmps)
2
0
-2
-4
-6
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.5—WTG terminal instantaneous current
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1.4
Total
Active
Reactive
1.2
Current (per unit)
1
0.8
0.6
0.4
0.2
0
2.9
2.92
2.94
2.96
2.98
3
3.02
3.04
3.06
3.08
3.1
3.12
3.14
3.16
3.18
3.2
Time (Seconds)
Figure I.6—WTG terminal RMS current
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Annex J
(informative)
Type III wind turbine generator (WTG) challenges with controllability of
negative-sequence current during unbalanced faults
The type III wind turbine is equipped with back-to-back ac-to-dc-to-ac converter in the machine’s rotor
circuit, where it is sized to about 30% to 35% of the rated power of the machine. The rotor-side converter is
used to impose voltage and current at a controlled frequency on the machine’s rotor windings.
For normal operating condition, the steady-state voltage in the rotor winding can be approximated as:
Vr = Vs × s × TR
(J.1)
where
Vs
is the stator voltage
s
is the slip
TR
is the turns ratio of the generator
The slip is typically between −0.3 and +0.3 per unit of nominal frequency or synchronous speed. Under
normal conditions, the voltage in rotor circuit is only +/− 0.3 per unit, which is the design basis of the rotorside converter.
The type III WTG naturally provides negative-sequence current during unbalanced faults based on machine
parameters and the pre-fault operating point. However, the angle between negative-sequence current and
voltage may not be precisely controllable. For unbalanced faults, large voltages are induced on the rotor
winding associated with negative sequence component of voltage in the stator because the slip for negative
sequence component is (2 − s). The overvoltages caused by unbalance do not decay and remain until the
unbalance condition is cleared. During unbalanced faults and depending on fault location, the negativesequence voltage could be much higher, and can induce voltages large enough to exceed the rotor side
converter voltage ratings. This could lead to one or both of the following: overmodulation of the rotor side
converter (e.g., partial loss of control) and/or rectification of the rotor side converter. For example, for a L-L
fault, where the negative-sequence stator terminal voltage is 40%, and a slip of −0.3, the negative-sequence
voltage in the rotor winding is then 92%. For a fault closer to WTG, the negative-sequence voltage would be
even higher. Additionally, there is also some positive-sequence voltage in the rotor winding resulting in a
much higher total voltage in the rotor winding.
In summary, due to challenges associated with controllability of the rotor-side converter, the angle between
the negative-sequence voltage and current during unbalanced faults cannot be precisely controlled. During a
transient period of 20 ms to 30 ms immediately after onset of a fault, the angle between the negative-sequence
voltage and current could be as high as 150°. Even few cycles after initiation of a fault, the negative-sequence
current could lead the voltage by 130° to 150°. At the time of development of this standard, the impact of
this large angle between negative-sequence voltage and current on dependability and security of traditional
protection schemes is not known. Based on engineering judgement, protection functions dependent on
negative sequence quantities may be negatively impacted. The transmission system (TS) protection engineers
are encouraged to consider this when applying protection schemes on transmission lines in close vicinity of
inverter-based resources (IBRs) consisting of type III WTGs.
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Additionally, at the time of development of this standard, type III WTG manufacturers are working to
improve the controllability of the rotor-side converter during unbalanced conditions. However, optimizing
controls of the rotor-side converter with focus on angle between negative-sequence voltage and current could
lead to a complex control structure. This also requires additional reserve voltage capacity for rotor windings
and the rotor-side converter, and therefore increased cost. As such, and following the purpose of this standard,
which is to specify minimum technical requirements, a precise control of angle between negative-sequence
voltage and current is not specified.
The TS protection engineer should investigate impact of the specified angle range, 90° to 150°, between
negative-sequence current and voltage. If not acceptable, consider specifying a more precise control of angle
between negative-sequence voltage and current.
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Annex K
(informative)
Guidance on fast frequency response (FFR)
K.1 Introduction to FFR variants
This section summarizes emerging examples for variants of FFR. The list in K.2 is not exhaustive.
FFR may be specified by the load balancing entity using some of the following parameters specified or using
one of the structured FFR described later:

Dead-band

Rate of change frequency (ROCOF)

Response time

Settling time of increased or decreased active power based on FFR

Maximum active power increase, may exceed inverter-based resource (IBR) continuous rating (ICR)
up to IBR short-term rating (ISR)

Maximum active power energy

Duration of active power increase

Dependence on initial operating point and resource available (wind speed, headroom, irradiance,
state of charge [SoC], etc.)

Allowable time to recover normal active power generation

Minimum generation level for FFR
K.2 Variants of FFR
An IBR plant may have the capability to enable any one of the forms of FFR listed in 6.2.2 or a combination
of multiple forms simultaneously. If more than one FFR form is enabled simultaneously, the total FFR may
be the sum of the FFR from each form. When FFR is enabled, the total IBR plant active power for
underfrequency condition may be as shown in the following equation:
{
=
p min pavl , ppre + pPFR + pPFR1 + pPFR2 + pPFR3 + pPFR4
}
(K.1)
Here, ppre, pPFR, pavl, pmin, and pFFR1 are as defined in Clause 6 and pFFR2, pFFR3, and pFFR4 are forms of FFR as
defined in the following subclauses.
Note that the equation above can be generalized to include “+ …pFFRx” at the end of that equation, where
pFFRx for x > 4 represents other forms of FFR that have not been included in this standard.
NOTE—Normally all but one of the types of FFR would be zero (disabled), though it may be beneficial to activate a mix
of more than one type.
Other forms of FFR not defined here may be permitted if allowed and defined by the transmission system
(TS) operator.
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The FFR response time capability, defined as the time from the triggering event to the time when the change
in active power due to FFR reaches 90% of its target value, may be adjustable to no greater than 1 s, including
the reaction time for triggering FFR. 201 Any overshoot may not exceed 10% of the change, and any
oscillations may be positively damped.
K.2.1 FFR1: FFR proportional to frequency deviation
Refer to the normative requirements in 6.2.2.1.
K.2.2 FFR2: FFR proportional to df/dt
An FFR2 response is proportional to the time derivative of frequency. The FFR2 capability of an IBR plant
may meet the performance requirement shown in Table K.1. The FFR2 parameters may be adjustable within
the ranges of available settings specified in Table K.2.
FFR2 implemented where there is no energy limitation, is identical to mechanical inertia. Here the energy
source is limited, such as in a wind turbine that is not pre-curtailed. Implementations of FFR2 where the
power does not continually flow in proportion to the derivative of frequency is an imperfect emulation of
inertia.
Table K.1—Formula for FFR2 (proportional to df/dt)
Low frequency
pFFR 2
0,
f > f UF,FFR2


=
df
−k UF,FFR2 × , f ≤ f UF,FFR2
dt

where
pFFR2
is the active power from FRR2 in p.u. of the IBR continuous rating (ICR) as defined in 3.1
f
is the applicable frequency in Hz
fUF,FFR2
is the underfrequency trigger for FFR2, in Hz
kUF,FFR2
is the constant gain for underfrequency events in per unit of ICR per Hz/s
Table K.2—Parameters of FFR2
Parameter
fUF,FFR2
kUF,FFR2
Units
Hz
p.u.
Default value
99.4% of fnom
0.5
Minimum
99.17% of fnom
0
Maximum
NA
5
K.2.3 FFR3: Fixed magnitude FFR with frequency trigger
An FFR3 response is a fixed-magnitude active power response triggered by frequency exceeding a threshold.
The FFR3 capability of an IBR plant may meet the performance requirement shown in Table K.3. The FFR3
parameters may be adjustable within the ranges of available settings specified in Table K.4.
201
Note that there are limitations on the response times that can be provided by WTGs due to the inertia-based response of the WTG
system. See NOTE 3 of 6.2.1 for description, and 6.2.3 for specification of WTG-based energy extraction.
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Once triggered, FFR3 remains at constant power (subject to availability of active power) until the conditions
for return to normal operations are met.
Table K.3—Formula for FFR3 (fixed magnitude with frequency trigger)
Low frequency
0,


pFFR3 = 

 PT3,UF ,
f > f UF,FFR3
f ≤ f UF,FFR3
where
pFFR3
is the active power from FRR3 in p.u. of the IBR continuous rating (ICR) as defined in 3.1
f
is the applicable frequency in Hz
fUF,FFR3
is the underfrequency trigger for FFR3, in Hz
pT3,UF
is the constant active power target for underfrequency events in per unit of ICR
Table K.4—Parameters of FFR3
Parameter
Units
Default Value
Minimum
Maximum
fUF,FFR2
Hz
99.4% of fnom
99.17% of fnom
NA
pT3,UF
p.u.
0.1
0
1
K.2.4 FFR4: Fixed magnitude FFR with df/dt trigger
An FFR4 response is a fixed-magnitude active power response triggered by the time derivative of frequency
exceeding a threshold. The FFR4 capability of an IBR plant may meet the performance requirement shown
in Table K.5. The FFR4 parameters may be adjustable within the ranges of available settings specified in
Table K.6.
Once triggered, FFR4 remains at constant power (subject to availability of active power) until the conditions
for return to normal operations are met.
Table K.5—Formula for FFR4 (fixed magnitude with df/dt trigger)
Low frequency
pFFR4
df

< dtrig UF,FFR4
 0,
dt
=
df
P
,
, ≥ dtrig UF,FFR4
 T4,UF dt
where
pFFR4
is the active power from FRR4 in p.u. of the IBR continuous rating (ICR) as defined in 3.1
f
is the applicable frequency in Hz
dtrigUF,FFR4 is the underfrequency trigger for FFR4 in Hz/s
pT4,UF
is the constant active power target for underfrequency events in per unit of ICR
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Table K.6—Parameters of FFR4
Parameter
Units
Default value
Minimum
Maximum
dtrigUF,FFR4
Hz/s
−0.5
−5.0
0
pT4,UF
p.u.
0.1
0
1
K.3 Conditions for return to normal operations
Because FFR1 and FFR2 have proportional responses, no additional requirements are specified for return to
normal operations. The FFR1 and FFR2 magnitudes inherently become zero when the frequency returns
within the trigger frequency fFFR1 or fFFR2.
An IBR plant performing FFR3 and FFR4 may begin its return to normal operation when either of the
following conditions are met:

Frequency returns above fnom for underfrequency

The hold time for FFR, Thold,FFR, has been exceeded. Thold,FFR may be adjustable within a range of
available settings between 5 s and 300 s with a default value of 10 s. 202
K.4 Performance when returning to normal operations
When the conditions for return to normal operation in K.3 are met, the FFR3 and FFR4 responses may ramp
to zero over a period Tramp,FFR. The Tramp,FFR may be adjustable within a range of available settings between
10 s and 1800 s with a default value of 300 s.
When recovering from providing FFR, wind turbine generator (WTG)–based IBR plants may be permitted
to reduce active power below the pre-event active power level if needed to return rotor speed to normal
operations.
Note that FFR2 and FFR4 respond to the rate of change of frequency, so their impact on frequency control
and stability should be carefully evaluated before use.
202
Note that there are limitations on the hold times that can be provided by WTGs due to the inertia-based response of the WTG system,
this is typically defined as 5 s to 10 s. See NOTE 3 of 6.2.1 for description, and 6.2.3 for specification of WTG-based energy extraction..
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Annex L
(informative)
Damping ratio
The concept of damping ratio is one that describes, as a dimensionless quantity, the measure of how the
oscillations in the response of a system decay over time after a disturbance.
Damping ratio is thus the ratio of the actual damping of the system to the damping level at critical damping.
Thus, damping ratio can vary from undamped (ζ = 0; i.e., system is continuously oscillating), to underdamped
(ζ < 1; i.e., system oscillates, but the oscillations are positively damped), to critically damped (ζ = 1; i.e., the
system has no overshoot and no oscillations), to overdamped (ζ > 1; i.e., even more sluggish than the critically
damped response). The critically damped response is the point which is the border between under- and
overdamping response.
Technically speaking, the concept of damping ratio applies to ideal second order linear systems. However,
for a real closed loop control system, such as voltage control in an inverter-based resource (IBR) plant, if a
small-signal step response test is performed (e.g., 1% to 5% reference step change and if no limits are hit
during the test), the damping ratio can be easily calculated from the measured response. This is illustrated by
the example below.
Consider an IBR plant where, as a test, a step is injected into the voltage reference set-point of the plant-level
closed-loop voltage control, which is controlling the voltage at the point of measurement (POM). Below are
three possible responses to such a test for three different gain settings of the controller.
Let us now consider the nature of the three plots:
1.
First consider Figure L.1. Upon simple visual inspection, and based on engineering judgement, it is
clear that the response with initial gain (blue trace) is probably the most preferred response, and the
response with double the gain (red trace) is also acceptable. However, the response having quadruple
the gain (magenta trace) is perhaps not acceptable as it is oscillatory and has a huge initial overshoot.
2.
For the initial gain (blue trace) the response is critically damped or better. Thus, one needs to
calculate the damping ratio; it is clearly ≥ 1. Thus, it meets the requirement of a damping ratio of
> 0.3.
3.
For the case having double the gain (red trace), the damping ratio may be calculated from the
overshoot, with the equation:
− ln(O)
ζ =
(L.1)
π 2 + ln 2 (O)
where
O
is per unit overshoot
For the example, in Figure L.2, the maximum value is 1.022. Thus,
=
O
(1.022 − 1.01) − (1.02 − 1.01)
= 0.2
(1.02 − 1.01)
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and thus, the damping ratio is:
− ln(0.2)
= 0.46
π 2 + ln 2 (0.2)
=
ζ
which is clearly > 0.3 and this meets the criterion.
4.
For the case having quadruple the gain (magenta curve), the damping ratio may be calculated using
the method of log-decrement, with Equation (L.2):
1
ζ =
 2π 
1+ 

 δ 
(L.2)
2
where the log-decrement δ is given by
δ=
1  YO 
ln 

n  Yn 
where
Yo
is the initial peak of the oscillations
Yn
is the nth peak of the oscillations
For the example case in Figure L.2, the first peak Yo = (1.0266 – 1.02) = 0.0066, and the n = 1 peak
is Y1 = (1.0223 – 1.02) = 0.0023. Thus, we get:
 0.0066 
=
δ ln=
 0.0023  1.0542


and
=
ζ
1
= 0.166
2
 2π 
1+ 

 1.0542 
This clearly fails our criterion of the damping ratio being > 0.3.
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Figure L.1—Step response of a simulated IBR plant to a 1% step change in the voltage
reference of the plant-level closed-loop voltage control. Simulated values are shown in per
unit at the POM.
Figure L.2—Step response of a simulated IBR plant to a 1% step change in the voltage
reference of the plant-level closed-loop voltage control. Simulated voltage at the POM.
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Annex M
(informative)
Consecutive voltage deviation ride-through capability of isolated inverterbased resources (IBRs) interconnected via voltage source converter highvoltage direct current (VSC-HVDC)
This annex is informative. It is intended to help readers understand the rationale for an exception introduced
in 7.2.2.4 for isolated IBRs interconnected to the ac transmission system via voltage source converter highvoltage direct current (VSC-HVDC) system.
The VSC-HVDC system is used to interconnect remote wind plants (e.g., offshore wind plants) where
interconnection via ac system is not economical or technically feasible considering active power losses and/or
challenges with providing necessary reactive power compensation. An example of offshore wind plant
interconnection via VSC-HVDC system is shown in Figure M.1. Several isolated IBRs, i.e., wind plants, can
be connected to an offshore ac-dc converter station via ac cables, transformers, and if necessary, reactive
power compensation equipment. The HVDC line connects the offshore ac-dc converter station to an onshore
dc-ac converter station. The onshore dc-ac converter station is equipped with a dc chopper and is connected
to the ac transmission system. This is where the default reference point of applicability (RPA), i.e., the point
of measurement (POM), is for the consecutive voltage deviations ride-through capability requirements
specified in 7.2.2.4.
Figure M.1—Offshore wind plant interconnection via VSC-HVDC system
The offshore ac-dc converter station controls voltage and frequency in the offshore ac network. The offshore
ac-dc converter station must inject the energy produced by offshore wind plants into the HVDC line.
Typically, direct communication between offshore ac-dc converter station and wind turbine generators
(WTGs) within the wind plant is not available.
The HVDC system (line and converter stations at each terminal) provides isolation between offshore and
onshore ac networks. As such, in case of a fault on the onshore ac transmission system, there is no impact on
voltage and frequency of the offshore ac network. During a fault or system disturbance on the onshore ac
transmission system, depending on voltage at the POM/point of connection (POC), the active power injection
from the onshore dc-ac converter station into the onshore ac transmission system is reduced or completely
interrupted for the duration of a fault/system disturbance. Due to the requirement to operate in the reactive
current priority mode, the active power injection from dc-ac converter station into the onshore ac
transmission system is significantly reduced or completely interrupted even for a fault far away from the
POM. This causes the rise in dc voltage and can lead to potential damage of the dc equipment. One alternative
to maintain dc voltage to an acceptable level is to stop or reduce injection of active power from offshore ac
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network (i.e., wind plants) into the dc line/link via ac-dc converter station. This requires reducing the active
power production by WTGs within the offshore wind plant. Without availability of communications between
ac-dc converter station and WTGs, this alternative is not feasible. Even if means of communication is
available, the delay in communication may be significant enough where active power production at WTGs
is not reduced in a time to keep the dc voltage below an acceptable level.
Another alternative is to use a dc chopper, which is located at the onshore dc-ac converter station as shown
in Figure M.1. The dc chopper absorbs the excess energy from the dc system to maintain the dc voltage to an
acceptable level. The energy absorption capability of the dc chopper is limited by the thermal design. Once
activated to absorb energy, the dc chopper needs time to cool down before it can be activated again to absorb
energy. Typically, the dc chopper is designed to absorb the IBR continuous rating (ICR) for 2 s and needs a
cool down time before it is capable to absorb energy again. This may limit the isolated IBRs interconnected
via VSC-HVDC from riding through consecutive voltage deviations requirements specified in 7.2.2.4. In
comparison, the type IV WTG also employs a medium-voltage dc chopper, however the cost and physical
size of a high-voltage dc chopper associated with HVDC systems increases with increased energy absorption
capability. The existing grid codes, such as the European Connection Conditions (ECC) and the German
Technical Connection Rule (TCR) VDE-AR-N 413, allow a limit on consecutive voltage deviations ridethrough capability considering the energy absorption capability and thermal design of the dc chopper.
Ongoing developments, such as reducing active power production from WTGs by changing the offshore ac
network voltage and frequency may help with improving the consecutive voltage deviation ride-through
capability with existing thermal design and energy absorption capability of the dc chopper. If it is feasible to
add communications between offshore ac-dc converter station and individual WTGs which in turn can be
used to send a signal to individual WTGs to reduce the active power output quickly, communications may
help improve consecutive voltage deviation ride-through capability in future. However, these alternatives are
not matured at the time of development of this standard. Hence, this standard allows an exception to isolated
IBRs connected via VSC-HVDC based on thermal design and energy absorption capability of the dc chopper.
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RAISING THE
WORLD’S
STANDARDS
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