Modeling Inverter-Based Resources in Short-Circuit Programs

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m

Evangelos Farantatos, Ph.D.Sr. Project ManagerGrid Operations & Planning R&D GroupEPRI

2020 PSS@CAPE User Group MeetingOctober 5, 2020

Modeling Inverter-Based

Resources in Short-Circuit

Programs

http://www.epri.com/

https://www.linkedin.com/company/epri

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https://twitter.com/EPRINews

© 2020 Electric Power Research Institute, Inc. All rights reserved.w w w . e p r i . c o m2

Motivation, Challenges & Needs

• Continuously increasing penetration level of inverter based resources (IBR), predominantly renewables (Type III, Type IV WTGs & PVs)

• Complex fault response

• Differs significantly from synchronous short-circuit current contribution (SCC)

• Accurate short-circuit models for protection/planning studies

• Performance of legacy protection schemes (distance protection etc.)

Challenge

Impact on System Protection



Agenda

1) IBR Technologies

2) IBR Modeling

3) IBR Short-Circuit Modeling

4) Impact of IBR on Transmission System Protection

5) Industry Activities



IBR Technologies



Type IV WTG

• Electrical generator:

• Induction generator

• Conventional synchronous generator

• Permanent magnet synchronous generator (PMSG)

• Full rated back to back AC/DC & DC/AC converter

• Stator Side Converter (SSC)

• Grid Side Converter (GSC)

• Resistive chopper for DC bus overvoltage protection

• Generator decoupled from the grid



Type IV WTG Control

• Vector control: Transforms ABC (AC) to dq

(DC) quantities

• GSC: Controls DC voltage and inverter

terminal voltage

• SSC: Applies Maximum Power Point Tracking

(MPPT) by controlling generator active power



Type IV WTG – Typical Fault Response



Type III WTG

• Electrical generator: Doubly Fed Induction Generator (DFIG)

• Partially rated (~30%) back to back AC/DC & DC/AC converter

• Rotor Side Converter (RSC)

• Grid Side Converter (GSC)

• Resistive chopper for DC bus overvoltage protection

• Generator not decoupled from the grid

• Crowbar may activate to short rotor windings and protect the converter. WTG behaves like a squirrel

cage induction machine



Type III WTG Control

• Vector control

• RSC: Controls DFIG active and reactive

power. Applies MPPT

• GSC: Controls DC voltage and may inject

reactive power



Type III WTG – Typical Fault Response



Type III WTG – Typical Fault Response – Crowbar Activation



Solar Photovoltaic

• Configuration and control are similar to a Type IV WTG



IBR Inverter Level & Plant Level Controls

VSCPWMInner

ControlOuter

ControlPlant

ControlSystem

PLL

V,IGate

PulsesModulating

SignalCurrent

ReferencesP,Q, or V

Plant Level V,I

ABC-DQ

Inverter Level ControlsPlant Level Controls



IBR Modeling



Generic vs User-Written Models

Generic ModelsUser-Written Models

• Documentation: technical specifications and

user guides available and public

• Portability across software platforms:

implemented and tested in major commercial

tools, and consistent across the tools

• Accuracy: might not represent accurately

actual control design

• Validation: validation and parameterization

based on field data can be performed

• Modeling the Future: generic models are

useful for performing futuristic studies where

the actual equipment to be used is not yet

known

• Detailed models developed by a specific

vendor of their own equipment/controls

• Based on actual control design

• Essential for detailed studies

• Proprietary, shared under NDA

• Black-box and so not easy to understand all

details

• Hard to debug/trouble shoot – software

vendors cannot support

• Not transportable across software platforms



2nd Generation WECC Renewable Energy System (RES) Models

Generator

Id

Iq

Vt

Drive-Train

wt1g

wt1t

Pitch-Control

wt1p_b

w

Pm

Generator

Id

Iq

Vt

Drive-Train

wt2g

wt1t

Pitch-Control

wt1p_b

w

Pm

External

Resistor

Control

wt2e

Rext

Generator/

Converter

Model

Iq

Ip

Iqcmd

Ipcmd

Current

Limit

Logic

Vt

Pqflag

= 1 (P priority)

= 0 (Q priority)

Q Control

P Control

Iqcmd’

Ipcmd’

Qref

(or Qext)

Qgen

Pref

(or PExt)

Drive-Train

spd

reec_a

regc_a

wtgt_a

Pord

Torque

Control

wtgtrq_a

Pe

Pref0

Pitch-Controlwtgpt_a

wref

qAero

wtgar_a Pm

Plant Level Control

repc_a

Vref/Vreg or

Qref/Qgen

At plant levelFreq_ref/Freq and

Plant_pref/Pgen

Generator/

Converter

Model

Iq

Ip

Iqcmd

Ipcmd

Current

Limit

Logic

Vt

Pqflag

= 1 (P priority)

= 0 (Q priority)

Q Control

P Control

Iqcmd’

Ipcmd’

Qref

(or Qext)

Qgen

Pref

(or TExt)

Plant Level Control

reec_a

regc_a

repc_a

Vref/Vreg or

Qref/Qgen


Plant_pref/Pgen

Generator/

Converter

Model

Iq

Ip

Iqcmd

Ipcmd

Current

Limit

Logic

Vt

Pqflag

= 1 (P priority)

= 0 (Q priority)

Q Control

P Control

Iqcmd’

Ipcmd’

Qref

(or Qext)

Qgen

Pref

(or TExt)

Plant Level Control

reec_b

regc_a

repc_a

Vref/Vreg or

Qref/Qgen


Plant_pref/Pgen

WTG Type 1 WTG Type 2

WTG Type 3

WTG Type 4

PV

•Latest renewable energy

models available in

commercial platforms for

dynamic studies (positive

sequence)

Energy Storage



2nd Generation WECC RES Models - Modules

REEC_* REGC_*

Plant level controller

model

Electrical controller

model

Generator/converter model

Capabilities

1. Q control, Voltage based droop, Line

compensation based

2. P control, Frequency based droop

Capabilities

1. Q control, V control (both P and

PI),Coordinated Q/V control

2. P control

3. P and Q priority for current limits

Capabilities

1. High voltage reactive current

management

2. Low voltage active current

management

Output

feeds

into

Output

feeds

into

Win

d turb

ine m

odels

(fo

r w

ind p

lants

only

)

REPC_*



EMTP Wind Park Models

DFIG WP

(AVM)

WP_AVM1

DFIG WP

(DM)

WP_DM1

CommonMask

U. Karaagac et al., “A generic EMT-type model for wind parks

with permanent magnet synchronous generator full size

converter wind turbines,” IEEE Power and Energy Technology

Systems Journal, vol. 6, no. 3, pp. 131–141, Sep. 2019.



Average Value vs Switching Model

VSC

Vta Vtb

Ic

Ib

Ia

Ec

Eb

Ea

P = 0.9Q = 0.0688V = 0.606

V

A

Vtc

R=

0V

R=

0V

R=

0V

A

B

C

Vs_c

Vs_b

Vs_a+

L

+

L

+

L

+

R+

R+

R

Average Model Implementation

Switching Model Implementation

Ic

Ib

Ia

Ec

Eb

Ea

A

B

C

Idc_p

Idc_n

IDC

IDC

1.0e-8 [ohm]

1.0e-8 [ohm]

1.0

e6 [

uF]

Idc_p1

Idc_n1

Vp

Vn

1.0

e6 [

uF]

*0.001

*-0.001

BRK_DC_P

R=

0R=

0

BRK_DC_N

Vs_c

Vs_b

Vs_a+

L

+

L

+

L

+

R+

R+

R

2

IIGBT

D

DIGBT

2

I

2

IIGBT

D

DIGBT

2

I

2

IIGBT

D

DIGBT

2

I

S1

S4 S6

S3

S2

S5



EMTP Relay Library



PSCAD Wind Park Models

Reference: User Guide for PV Dynamic Model Simulation Written on PSCAD Platform


https://www.nrel.gov/docs/fy15osti/62053.pdf


DOE PV-MOD: Project Overview2

02

0 • Field data collection

• Smaller kW inverter characterization (lab testing)

• Gap analysis of PV models (dynamic, short-circuit, EMT/HIL, PQ)

• Inverter models for quasi-static time series (QSTS)

20

21 • Grid scale inverter

characterization (NREL)

• Develop initial versions of refined or newly developed models

• Provide model specs to vendors

• Model validation using the newly developed models

20

22 • Complete model validation

• Refine models based on validation

• Finalize specs for models & work with vendors

Validated; publicly available models for various types of studies, reports detailing the work, close collaboration with industry stakeholders (NERC, WECC, IEEE etc.)

Model Development

Resource Characterization

Model Commercialization

Adaptive Protection Application

Existing Models

Lab Tests

Field Data

Stability (PSS/E, PSLF, …)

Protection (CAPE, CYME, …)

EMT (EMTDC, EMTP-RV, …)

Test

Validate

Develop Design

Demonstration

HIL Testing

Unit, Plant & Aggr. Feeder/BTM

1 2 3 4

5QSTS (CYME, Synergi,…)



IBR Short-Circuit Modeling



Inverter Based Resources Fault Response Characteristics

Synchronous Generator

Type IV WTG

•SCC magnitude close to nominal load current

(typically 1.1-1.5 pu)

• Initial transient (typical duration 0.5 -1.0 cycle) –

uncontrolled response – controller “reaction time”

•Fault current can be capacitive, inductive or resistive

•Typically low negative sequence current contribution

•No zero sequence current



IBR Short-Circuit Modeling

Synchronous generator classical short circuit model (voltage

source behind an impedance) is not applicable

• EPRI Project 173.09 “Impact of Renewables on System Protection”

• IEEE PSRC WG C24 “Modification of Commercial Fault Calculation Programs

for Wind Turbine Generators”



EPRI Model



Inverter Generic Control Mode Options

Function Control Mode Performance/Description

Reactive

power/voltage

control during ride-through

Constant power factor

Allows for inverter injection/absorption of

reactive power based on a desired power factor

Constant Q

Allows for inverter fixed desired value of reactive

power injection/absorption

V ControlAllows for inverter control of

voltage to desired value

Dynamic reactive current injection (FRT)

Allows for reactive current

injection based on a reference

curve (e.g. grid code)



Dynamic Reactive Current Injection

• Reactive power/voltage

control during ride-through

• Positive sequence reactive

current injection based on a

specific control logic and/or

grid code

• Typically, reactive current

proportional (2<k<10) to

voltage drop

Example: For Vfault_pos=0.5 p.u and k=2 Ireact_pos=2*(1-0.5)=1 p.u

Ireact_pos=k*(1-Vfault_pos)



IBR Negative Sequence Fault Current

• IBR negative sequence fault current depends on

the inverter control

• For Type IV WTG & Solar PV: typically low

negative sequence current, but varies among

inverter manufacturers

• Type III WTG injects negative sequence current

• No industry standardization (topic under IEEE

P2800), only few exceptions

• German grid code requires negative

sequence fault current injection

• Negative sequence current control:

• Coupled Control: Elimination of negative

sequence current injection

• Decoupled control: Negative sequence

current injection based on grid code/control

logic, e.g. German Grid code

22.5 MVA Solar Plant: I2 & V2

Source: Dominion Energy



German Grid Code

• Negative sequence current injection

proportional to the negative sequence

voltage

• Gain/Slope: 2<k<6

• At a first glance looks like equivalent to

synchronous generator with 1/k pu

negative sequence reactance

• Current is limited (e.g. 1.2 pu)

• Active positive sequence current

• Reactive positive sequence current

• Reactive negative sequence current

VDE-AR-N 4120

BUT

Example: For Vneg=0.25 p.u and k=2 Ineg=2*0.25=0.5 p.u

Ineg=k*(Vneg)



Current Limiter - PQ Priority

lim

dg dgI I

lim

qg qgI I

2 2

limdg qgI I I −

Q-priority:

lim

dg dgI I

lim

qg qgI I

2 2

limqg dgI I I −

P-priority:

• Ilim: Total limit

• Individual Id_lim and Iq_lim might apply



Example 1

Assume:

- Active Power: 1 p.u.

- Post Fault Voltage: 0.7 pu

- Dynamic Reactive Current: k=2

- Q Priority

- Ilimit=1.1 pu

Desired Currents:

Iactive= 1/0.7=1.43 p.u

Ireactive=2(1-0.7) = 0.6 p.u

Itotal=1.55 pu (exceeds limit)

Upon current limiter:

Iactive= 0.92 (reduced to satisfy

limit)

Ireactive= 0.6 p.u

Itotal= 1.1 pu



Example 2

Assume:

- Active Power: 1 p.u.

- Post fault voltage: 0.4 pu

- Dynamic Reactive Current: k=2

- Q priority

- Ilimit=1.1 pu

Desired Currents:

Iactive= 1/0.4=2.5 p.u

Ireactive=2(1-0.4) = 1.2 p.u

Itotal=2.77 pu (exceeds

limit)

Upon current limiter:

Iactive= 0 (reduced to satisfy

limit)

Ireactive= 1.1 p.u (reduced

to satisfy limit)

Itotal= 1.1 pu



EPRI IBR Phasor Domain Short-Circuit (SC) Model

•Voltage controlled current source

• Iterative solution (nonlinear behavior)

• considers the impact of inverter controls on the short circuit response

• respects inverter current limits



Iterative Solution



Demonstrating Results – Type IV

Type IV WTG - LLG fault (AB) - BUS 1

•Type IV WTG/Solar model assumes zero

negative sequence current contribution



Demonstrating Results – Type III

Type III WTG - LL fault (AB) - BUS 4

•Type III WTG has negative sequence current

contribution due to the DFIG stator connection

to the grid



Negative Sequence Current Control – German Grid Code

Implementation

Control Mode: Dynamic Reactive Current Injection (k=2), Q Priority

Coupled German code (k=2)

WTG variable EMTP-RV Solution Phasor Domain Solution EMTP-RV Solution Phasor Domain Solution

Vpos 0.710 (23.9) 0.710 (24.1) 0.720 (6.9) 0.720 (6.9)

Ipos 1.135 (-10.7) 1.135 (-10.4) 0.743 (-50.4) 0.743 (-50.5)

Vneg 0.336 (-120.1) 0.337 (-117.4) 0.213 (-118.1) 0.213 (-118.0)

Ineg 0.063 (97.2) 0.0 (N/A) 0.407 (-28.1) 0.407 (-28.0)



German Grid Code – Impact of k

k=2 k=6

V2,lv (pu) 0.29 0.24I2,des (pu) 0.58 1.44I2q,ref (pu) -0.30 -0.49I1q,ref (pu) 0.70 0.51I2d,ref (pu) -0.44 -0.46I1d,ref (pu) -0.02 -0.00

angle(I2-V2) (°) 85.0 100.6

• I1q and I2q have the

same priority, and

are proportionally

reduced if needed



Model Non-Convergence Cases

• For some scenarios (typically close-in three-phase faults with no other source of

fault current between converter and fault) the desired current power factor

calculated by the controller cannot be imposed due to violation of physics laws (the

network impedance phase angle has to be satisfied)

• Issue is related to converter synchronization to the grid which in reality is provided

by the PLL

• Solution: Fix power factor based on network impedance or use pre-fault voltage

angle as a reference

Source: Charlie Henville “Power factor of electronic sources under normal and fault conditions” presentation at the PSRC WG C24



IEEE PSRCC & Vendor Engagement

•Goal: Vendor engagement and

implementation of the models in

commercial platforms

(PSS®CAPE, ASPEN OneLiner,

CYME, PowerFactory, etc)

•Leading Role at the IEEE

PSRCC WG C24 “Modification of

Commercial Fault Calculation

Programs for Wind Turbine

Generators”



PSRCC WG C24



PSRCC WG C24 “Modification of Commercial Fault Calculation

Programs for Wind Turbine Generators”

• Chair: Dr. Sukumar Brahma (Clemson University), Vice-Chair: Evangelos Farantatos (EPRI)

• Scope:

•1) To survey WTG manufacturers to determine what parameters they could provide that could

be used by steady state short circuit program developers in various time frames

•2) Use the result of this survey to prepare a report that can be used by steady state program

developers to refine their models

• Members include:

• WTG manufacturers (Siemens/Gamesa, Vestas, GE)

• Software vendors (Siemens (former Electrocon), ASPEN, ETAP)

• WG has proposed a voltage controlled current source model with iterative solution

• IBR Model:

• Algorithms for generic inverter control schemes (EPRI proposal)

• Tabular format (suggested to be provided by manufacturers based on OEM inverter control

scheme)



PSRCC WG C24 IBR Model

Time frame 1 (seconds or cycles) Fault Type: xxx

Positive sequence voltage (pu)

Positive sequence current (pu)

Positive sequence current angle with respect to positive

sequence voltage (deg)

0.9

0.7

0.5

0.3

0.1

Time frame 1 (seconds or cycles) Fault Type: xxx

Negative sequence voltage (pu)

Negative sequence current (pu)

Negative sequence current angle with respect to negative

sequence voltage (deg)

0.9

0.7

0.5

0.3

0.1

•Tabular format

•Separate tables for

different time frames

•Separate tables for

balanced & unbalanced

faults

•Values depend on the pre-

fault WTG active power



PSRCC WG C24 Report

Published!


https://www.pes-psrc.org/kb/published/reports/C24_WG_Report_Jun_2020_Final.pdf


Siemens PSS®CAPE



PSS®CAPE Implementation – Siemens (former Electrocon)

• EPRI Type IV WTG/Solar PV model has

been implemented

• Voltage Controlled Current Source model

has been implemented

• EPRI and Siemens have benchmarked the

Type IV WTG model

• EPRI Type III WTG model is under

development

• No fault contribution for voltages above

0.9pu (load current) – based on a

suggestion by a CAPE user

• PSS®CAPE UGM Documents

• Siemens contributed to the PSRCC WG

C24 report



PSS®CAPE Implementation – Siemens – EPRI Type IV WTG/Solar PV

• Control Modes:

• Dynamic Reactive Current (referred to as FRT)

• Voltage Control

• Reactive Power Control

• Power Factor Control

• Negative sequence fault current injection based on German grid code under development



PSS®CAPE Implementation – Siemens – VCCS Model

• Only positive sequence – no table for negative sequence

• Only one table (no option for multiple time frames)



EPRI Benchmarking

Faulted bus ImplementationV_mv I_mv PF at MV V_lv I_lv PF at LV

pu deg pu deg deg pu deg pu deg deg

3

EPRI MV code 0.44 -11.3 1.15 -73.3 -62.00 0.55 23.30 1.10 -42.1 -65.40CAPE EPRI Type IV WTG 0.43 -8.21 1.15 -67.53 -59.32 0.53 27.04 1.10 -36.34 -63.38EPRI LV code 0.43 -7.74 1.14 -64.48 -56.74 0.52 28.92 1.10 -32.94 -61.86CAPE VCCS at MV 0.42 -5.30 1.15 -62.00 -56.70 NA NA NA NA NACAPE VCCS at LV 0.42 -5.30 1.15 -62.20 -56.90 0.52 31.10 1.10 -30.98 -62.08

4

EPRI MV code 0.62 -7.70 1.15 -47.50 -39.80 0.71 28.90 1.10 -15.00 -43.90CAPE EPRI Type IV WTG 0.62 -7.72 1.15 -48.72 -41.00 0.71 28.70 1.10 -14.70 -43.40EPRI LV code 0.58 -5.94 1.14 -39.22 -33.27 0.65 31.90 1.10 -9.92 -41.82CAPE VCCS at MV 0.58 -4.00 1.14 -37.80 -33.80 NA NA NA NA NACAPE VCCS at LV 0.58 -4.00 1.14 -37.90 -33.90 0.65 34.10 1.10 -5.38 -39.48

5

EPRI MV code 0.81 -7.10 1.10 -25.30 -18.20 0.86 29.60 1.07 8.90 -20.70CAPE EPRI Type IV WTG 0.80 -6.23 1.10 -24.67 -18.44 0.86 30.60 1.07 9.48 -21.12EPRI LV code 0.80 -8.60 1.08 -23.60 -15.00 0.84 27.98 1.05 10.10 -17.88CAPE VCCS at MV 0.79 -6.10 1.08 -21.70 -15.60 NA NA NA NA NACAPE VCCS at LV 0.79 -6.00 1.09 -21.60 -15.60 0.83 31.20 1.06 12.55 -18.66

6

EPRI MV code 0.87 -10.00 1.06 -23.20 -13.20 0.91 26.40 1.04 11.50 -14.90CAPE EPRI Type IV WTG 0.87 -8.58 1.07 -22.78 -14.20 0.91 27.80 1.04 11.91 -15.89EPRI LV code 0.86 -11.04 1.04 -21.32 -10.28 0.89 25.20 1.02 13.00 -12.20CAPE VCCS at MV 0.85 -8.70 1.04 -20.30 -11.60 NA NA NA NA NACAPE VCCS at LV 0.85 -8.40 1.05 -19.40 -11.00 0.88 28.30 1.04 15.75 -12.55



Model Validation



Model Validation – 3 Approaches

Generic EMT Models

OEM Provided Models

Fault Records



Case 1: Type-III Wind Park Connected to a 230-kV Substation

▪ The wind plant is connected to a 230kV point of interconnection (POI). It embeds 66x1.5MW type-III wind turbine generators connected to three 34.5kV collector circuits to the collector substation.

▪ The 34.5/230kV step-up transformer in the collector substation is a wye-delta-wye transformer.

▪ The 230kV tie line between the collector substation and the POI substation is 18.7km long.

▪ Prior to the fault all 66 wind turbine generators were connected to the system and the plant was delivering 25.69MW and absorbing 1.35MVar from the 230kV system at the collector substation.

▪ The wind speed was 6.5m/s.

▪ The fault was a B–C phase to phase on the tie line 3.5km from the POI substation.

+

VwZ1

230kVRMSLL /_0

PI

+

Line_LATIGO_3BUTTES

WP_DFIG1

DFIG AVM110.022MVA230kVQ-control

LFLF1

Slack: 230kVRMSLL/_0Vsine_z:VwZ1

+Relay_Wind

+Relay_Transmission

6604_LATIGO

V1:1.00/_-0.00V2:0.00/_102.09V0:0.00/_45.00Va:1.00/_0.00Vb:1.00/_-120.00Vc:1.00/_120.00

11847_THREE_BUTTES

V1:1.00/_0.2V2:0.00/_-89.8V0:0.00/_-89.8Va:1.00/_0.2Vb:1.00/_-119.8Vc:1.00/_120.2



Case 1: Relay Records vs. EMTP Simulation Results



Case 1: Phasor Model Results

Variable

Stator + GSC - pu

EMTP-RV Phasor Solution

0.768 (-36.2) 0.743 (-53.8)

0.640 (12.0) 0.658 (7.4)

0.894 (104.9) 0.900 (98.0)

0.317 (-5.3) 0.310 (-1.9)

I+

V+

I−

V−

Variable

POI - pu


0.825 (-39.7) 0.810 (-56.4)

0.509 (1.5) 0.509 (0.6)

0.858 (105.8) 0.862 (98.4)

0.488 (0.4) 0.486 (0.1)

I+

V+

I−

V−

Variable

POI – Magnitudes – Actual Values


228 A 223.8 A

67.6 kV 67.63 kV

237 A 238.0 A

64.8 kV 64.50 kV

I+

V+

I−

V−

Values are for 2nd cycle after fault



Case 2: Type-III Wind Park Connected to a 115-kV

Substation

▪ The wind plant is connected to a 115-kV POI/collector substation. It embeds 11x1.5MW type-III wind turbine generators connected to a 34.5kV collector circuit.

▪ The 34.5/230kV step-up transformer in the collector substation is a wye-delta-wye transformer.

▪ The 115-kV tie line from the POI/collector substation to network substation is 10.7 km long.

▪ Prior to the fault all 11 wind turbine generators were connected to the system and the plant was outputting 17.7 MW and 3.2 MVar into the grid.

▪ The fault was a phase-A-to-ground on the line to the network substation, 3.8 km from the network substation.

+

VwZ1

115kVRMSLL /_0

WP_DFIG1

DFIG AVM18.337MVA115kVQ-control

LFLF1

Slack: 115kVRMSLL/_0Vsine_z:VwZ1

+Relay_Wind

+ Relay_Transmission

PI

+

Line_Casper2_RAWHIDE

PI

+

Line_1717_2157

PI

+

Line_2480_1717

2157_CASPER

V1:1.00/_-0.00V2:0.00/_116.57V0:0.00/_0.00Va:1.00/_-0.00Vb:1.00/_-120.00Vc:1.00/_120.00

2197_Casper_2

V1:1.01/_0.8V2:0.00/_90.8V0:0.00/_90.8Va:1.01/_0.8Vb:1.01/_-119.2Vc:1.01/_120.8

8570_RAWHIDE

V1:1.01/_0.7V2:0.00/_-89.3V0:0.00/_-89.3Va:1.01/_0.7Vb:1.01/_-119.3Vc:1.01/_120.7

2480_CHEW_SW1

a

V1:1.00/_0.3V2:0.00/_90.3V0:0.00/_90.3Va:1.00/_0.3Vb:1.00/_-119.7Vc:1.00/_120.3

1717_BUS179



Case 2: Relay Records vs. EMTP Simulation Results



Case 2: Phasor Model Results

Variable

Stator + GSC - pu


0.991 (-7.5) 0.936 (-17.1)

0.913 (19.4) 0.943 (16.5)

0.431 (-78.4) 0.404 (-82.2)

0.133 (174.6) 0.139 (178.0)

I+

V+

I−

V−

Variable

POI - pu


1.109 (-18.5) 1.082 (-28.0)

0.762 (1.1) 0.762 (0.6)

0.394 (-76.9) 0.364 (-81.2)

0.242 (-178.0) 0.242 (-178.3)

I+

V+

I−

V−

Variable

POI – Magnitudes – Actual Values


102.1 A 99.61 A

50.6 kV 50.58 kV

36.3 A 33.51 A

16.1 kV 16.07 kV

I+

V+

I−

V−

Values are for 2nd cycle after fault



BESS SC Model



Battery Energy Storage System EMT Model

AC_GSC

+10M

block_GSC

Chopper

Vref_GSC

VdcV+

-

VSC-AVM

+

N

P

AC

v arefv brefv cref

Blocked

VSC_AVM1

a

b

c

+R

chopper

IGBT_chopper

c#Vdc_V#

c2

c68108.5

+

BUCK-BOOSTAVM

d mo

de

i b vg

vg(ref)

d

mo

dei b vg+

SOC

vg(ref)

CONTROL

t ype

ib(ref)

t ype

ib(ref)

mode

BUCK_BOOST

Buck-Boost Model and Controller

VSC Model: Same as PV and Wind

Li-ion BESS Model&

DC-link

• BESS EMT model under development to understand impact of controls on fault current



BESS EMT Model – Sample Results

• Fault response during discharging, similar to PV and Type IV WTG• Fault response during charging is more complex

• Should discharge continue during fault?



Protection Guidelines



Protection System Performance Evaluation - Guidelines

• Study relays response & identify relay

misoperation scenarios on benchmark

systems with IBRs

• Provide recommendations and study

practices to protection engineers when

conducting protection studies to

prevent relay

misoperation/miscoordination

Negative Sequence Based Protection

Line Differential Protection

Communication Assisted Protection

Line Distance Protection

Power Swings Protection



Impact of IBR on Negative Sequence Based Protection

▪ Amplitude and angular relation of negative-

sequence quantities are important for

negative sequence based protection

elements

▪ Potential misoperation of legacy negative-

sequence-based protection schemes.

1. Negative-sequence overcurrent element

2. Negative-sequence-based directional

element

3. Fault Identification

4. Communication assisted protection



EPRI White Paper

“Impact of IBR Negative Sequence Fault Current Injection Methods on Negative-

Sequence Based Protection Schemes Performance”

• Outline

1. Introduction

2. Fault Behavior of Rotating Machines

3. Negative-Sequence Based Protection Schemes

4. Negative Sequence Fault Current Contribution

from Inverter-Based Resources

5. Impact of Inverter-Based Resources on

Negative-Sequence Protection Schemes


https://www.epri.com/#/pages/product/000000003002016197/?lang=en-US


Misoperation of Negative-Sequence Overcurrent Element (50Q) –

Results

▪ Type IV: Misoperation

due to low negative-

sequence current

▪ Type III: No

misoperation because of

negative-sequence

current injection higher

than pick up setting



Test System



Negative-Sequence Overcurrent Element (50Q) – German Grid

Code

▪ AG fault

▪ 50Q pickup: 0.25 pu

▪Negative sequence

current injection based

on the German grid

code mitigates the 50Q

misoperation



Misoperation of Directional Negative-Sequence Element (67Q) –

Results

Source: M. Nagpal and C. Henville, “Impact of power electronic sources on transmission line ground fault protection,”

IEEE Trans. Power Del, 2018



Misoperation of Directional Negative-Sequence Element (67Q) –

Results

▪Forward fault

▪Misoperation for Type 4 WTG with coupled control

▪Negative sequence current injection based on the German grid code mitigates the issue

Scenario Angle(Z2) (°)Declared fault

direction

SG -94 Forward

FSC CSC 120Reverse

(misoperation)

FSC German -93 Forward



▪ FID implemented by measuring the phase angle between the negative sequence and zero sequence currents

▪ Impact of IBR on the phase angle of negative sequence current may adversely influence the operation of FID

Impact of Inverter-Based Generation on Line Distance Protection –

Fault Identification (FID) Scheme

Typical FID Operating RegionsFID Misoperation Example for AG Fault



Misoperation of FID – Results

▪AG Fault

▪Misoperation for Type 4 WTG with coupled control


Scenario Angle(IA2) (°) Fault Type Sector

SG -4 AG/BCG

FSC CSC -140 CG/ABG (incorrect)

FSC German -4 AG/BCG



▪ Elements of communication-assisted protection:

1. Distance elements

2. Directional elements

▪ Schemes studied:

1. Permissive overreaching transfer trip (POTT)

2. Permissive underreaching transfer trip (PUTT)

3. Directional comparison blocking (DCB)

Impact of Inverter-Based Generation on Communication-

Assisted Protection

Source: SEL “Introduction to Power System Protection”



Case 1: POTT▪ Two relays R1 and R2 incorporating POTT based on 67Q2 and 21P_Z2

▪ AB fault on 93.3% of the line from R1, should be picked up by Z2 of R1 and Z1 of R2

▪ POTT operates when both 67Q2 and 21P_Z2 are issued

Wind farm on series compensated system

location 4


Radially compensated wind farm


location 1


location 3


location 2

+

Source1

LF

LF_source1

CP+

CP+

CP+

CP+

CP+

CP+

ZnO

CXC1

CP+

CP

+

CP+

CP

+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

2

3

1

315/120/12.5

2

3

1

315/120/12.5

+

+

LF

30MW

0

Load1

CP+

CP+

1 2

-30

120/25 1 2

-30

120/25

LF

30MW

0

Load3

1 2

-30

120/25

CP+

CP+

LF

30MW

0

Load4

1 2

-30

230/25

LF

30MW

0

Load5

1 2

-30

230/25

LF

30MW

0

Load6

CP+

+ZnO

29979

+

132.6uF

+

-1|1|0

CP+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

CP+

VM+m1 VM+

m2

VM+m3

VM+m5

VM+m6

VM+m7

VM+m8

VM+m9

View Steady -State

1 2

-30

230/25

LF

30MW

0

Load71 2

-30

230/25

LF

30MW

0

Load8

View Power Load Flow

Data function

ZnO

20ohms_1ka_2.3pu_sc10ka.dat

model in: 20ohms_1ka_2.3pu_sc10ka.pun

LF

30MW

0

Load2

CP +

LFLF3

Phase:0

+

VwZ3

?v

CP+

1 2

-30

230/25

VM+V120

FFC_WP1

FC AVM

333.4000MVA

315kV

Q-control

+

-1|1

E15|0

+

-1|1

E15|0

+

-1|1E15|0

+fault2 ?i

1|1E15|0

+

-1|1

E15|0

CP

+

FFC_WP4

FC AVM

333.4000MVA

315kV

Q-control

FFC_WP2

FC AVM

221.711MVA

230kV

Q-control

inout

W

inout R

inout

L1W

inout L1R

CP

+

CP

+

FFC_WP3

FC AVM

333.4000MVA

315kV

Q-control

R-X graph plotter

CP

+

1 2

-30

230/25

LF

90MW

45MVAR

25kVRMSLL

Load9

FFC_WP5

FC AVM

443.422MVA

230kV

Q-control

V1:329.94/_10.3 V1:324.40/_1.6

V1:243.06/_8.3

V1:122.63/_5.7

V1:239.87/_10.0

V1:121.79/_3.6

V1:240.70/_13.3

V1:315.00/_-0.0

AB1

R1

R2



• R2 keys permission for POTT by issuing both

21P_Z2 and 67Q2 (zone 2 forward picks up)

• R1 also issues both 21P_Z2 and 67Q2 (zone 2

forward picks up)

• POTT operates

Case 1: POTT - Results

Synchronous Generation Scenario Wind Generation Scenario

• R2 keys permission for POTT by issuing both

21P_Z2 and 67Q2 (zone 2 forward picks up)

• 21P_Z2 of R1 asserts (fault detected in zone 2),

but 67Q2 asserts only transiently

• POTT mis-operates. The misoperating element

is 67Q of R1 which does not see the fault as

forward or reverse



POTT – Impact of Negative Sequence Current Control





location 4


Radially compensated wind farm


location 1


location 3


location 2

+

Source1

LF

LF_source1

CP+

CP+

CP+

CP+

CP+

CP+

ZnO

CXC1

CP+

CP

+

CP+

CP

+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

2

3

1

315/120/12.5

2

3

1

315/120/12.5

+

+

LF

30MW

0

Load1

CP+

CP+

1 2

-30

120/25 1 2

-30

120/25

LF

30MW

0

Load3

1 2

-30

120/25

CP+

CP+

LF

30MW

0

Load4

1 2

-30

230/25

LF

30MW

0

Load5

1 2

-30

230/25

LF

30MW

0

Load6

CP+

+ZnO

29979

+

132.6uF

+

-1|1|0

CP+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

CP+

VM+m1 VM+

m2

VM+m3

VM+m5

VM+m6

VM+m7

VM+m8

VM+m9

View Steady -State

1 2

-30

230/25

LF

30MW

0

Load71 2

-30

230/25

LF

30MW

0

Load8


Data function

ZnO



LF

30MW

0

Load2

CP +

LFLF3

Phase:0

+

VwZ3

?v

CP+

1 2

-30

230/25

VM+V120

FFC_WP1

FC AVM

333.4000MVA

315kV

Q-control

+

-1|1

E15|0

+

-1|1

E15|0

+

-1|1E15|0

+fault2 ?i

1|1E15|0

+

-1|1

E15|0

CP

+

FFC_WP4

FC AVM

333.4000MVA

315kV

Q-control

FFC_WP2

FC AVM

221.711MVA

230kV

Q-control

inout

W

inout R

inout

L1W

inout L1R

CP

+

CP

+

FFC_WP3

FC AVM

333.4000MVA

315kV

Q-control

R-X graph plotter

CP

+

1 2

-30

230/25

LF

90MW

45MVAR

25kVRMSLL

Load9

FFC_WP5

FC AVM

443.422MVA

230kV

Q-control

V1:329.94/_10.3 V1:324.40/_1.6

V1:243.06/_8.3

V1:122.63/_5.7

V1:239.87/_10.0

V1:121.79/_3.6

V1:240.70/_13.3

V1:315.00/_-0.0

AB1

R1

R2

Case 2: PUTT▪ Under-reaching Z1 element keys permission, overreaching Z2 element trips on receipt of signal.

▪ Mid-line ph-ph fault AB1 on 93.3% of the line from R1.

▪ Correct operation of PUTT means Z1 of R2 keys permission, Z2 of R1 trips on receipt of signal.



• Under-reaching Z1 of R2 keys permission for PUTT

by issuing 21P_Z1

• Over-reaching Z2 of R1 asserts 21P_Z2; 67Q2

asserts;

• PUTT operates

Case 2: PUTT - Results


• Under-reaching Z1 of R2 keys permission for

PUTT by issuing 21P_Z1

• Over-reaching Z2 of R1 asserts 21P_Z2 but

67Q2 asserts only transiently

• PUTT misoperates. The malfunctioning element

is 67Q of R1 which does not see the fault as

forward or reverse



Case 3: DCB

Wind farm on series compensated systemlocation 4

Wind farm on series compensated systemRadially compensated wind farm




+

Source1

LF

LF_source1

CP+

CP+

CP+

CP+

CP+

CP+

ZnO

CXC1

CP+

CP

+

CP+

CP

+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

2

3

1

315/120/12.5

2

3

1

315/120/12.5

+

+

LF Load1

30MW

0

CP+

CP+

1 2

-30

120/25 1 2

-30

120/25

LF Load3

30MW

0

1 2

-30

120/25

CP+

CP+

LF Load4

30MW

0 1 2

-30

230/25

LF Load5

30MW

0 1 2

-30

230/25

LF Load6

30MW

0

CP+

+ZnO

29979

+

132.6uF

+

-1|1|0

CP+

2

3

1

315/230/12.5

2

3

1

315/230/12.5

+

+

CP+

VM+m1 VM+

m2

VM+m3

VM+m5

VM+m6

VM+m7

VM+m8

VM+m9

View Steady-State

1 2

-30

230/25

LF Load7

30MW

0

1 2

-30

230/25

LF Load8

30MW

0


Data function

ZnO



LF Load2

30MW

0

CP +

LF

Phase:0

LF3

+ ?v

Vw Z3

CP+

1 2

-30

230/25

VM+V120

FC AVM

333.4000MVA

315kV

Q-control

FFC_WP1

+

-1|1

E15|0

+

-1|1

E15|0

+

-1|1E15|0

+

1|1E15|0

?ifault2

+

-1|1

E15|0

CP

+

FC AVM

333.4000MVA

315kV

Q-control

FFC_WP4

FC AVM

221.711MVA

230kV

Q-control

FFC_WP2

ino

ut

W

ino

ut R

ino

ut

L1W

ino

ut L1R

CP

+

CP

+

FC AVM

333.4000MVA

315kV

Q-control

FFC_WP3

R-X graph plotter

CP

+

1 2

-30

230/25

LF Load9

90MW

45MVAR

25kVRMSLL

FC AVM

443.422MVA

230kV

Q-control

FFC_WP5CP+

V1:329.94/_10.3 V1:324.40/_1.6

V1:243.06/_8.3

V1:122.63/_5.7

V1:239.87/_10.0

V1:121.79/_3.6

V1:240.70/_13.3

V1:315.00/_-0.0

AB2

R3

R4

▪ Each line terminal has reverse-looking elements (Zone 3) and forward-overreaching elements (Zone 2).

▪ The relay sends a blocking signal to the remote terminal if it detects a fault in the reverse direction, indicating that the fault is outside of the protected zone.

▪ Relay trips if it sees the fault in the forward direction and does not receive a blocking signal from the remote terminal.



• Overreaching Z2 of R3 asserts. It should be blocked

by R4

• Reverse Z3 of R4 asserts; 67Q3 asserts. R4 issues

blocking signal

• DCB operates as expected

Case 3: DCB - Results


• Overreaching Z2 of R3 asserts. It should be

blocked by R4

• Reverse Z3 of R4 asserts but 67Q3 asserts only

transiently. R4 does not issue blocking signal

• DCB misoperates. The malfunctioning element is

67Q3 of R4 which does not see the fault as

forward or reverse



Phase Comparison Line Protection (87PC)

▪ The PC protection differentiates between an internal and external fault by comparing the phase angle of currents entering line terminals:

– Internal fault: In-phase

– External fault: 180° out of phase

▪ PC schemes:

– I2 excitation (using I2)

– Mixed excitation (using a mix of I1 and I2)



SG FCS WTG-Coupled Sequence Control FCS WTG-German code control

• I2 is reactive (at all line terminals).

• Power factor of I2 depends on inverter control scheme; may be resistive, inductive, or capacitive.

• This different current phase angle may produce a spurious shift in the phase angle of line terminal currents, potentially causing PC misoperation.

• Inverter is required to inject a reactive I2.

• Expected to mitigate the potential PC misoperation.

Expected Misoperation due to IBR



PC Misoperation - Demonstrating Results

SG FSC WTG CSC FSC WTG German

Misoperation

▪ Case 1: PC with I2 excitation



PC Misoperation - Demonstrating Results

SG FSC WTG CSC FSC WTG German

Misoperation

▪ Case 2: PC with mixed excitation (𝐼𝑚𝑖𝑥 = 𝐼2 − 0.2𝐼1)



▪Immune to

misoperation

Impact of Inverter-Based Generation on Line Current Differential

(LCD) ProtectionTraditional LCD

Alpha Plane LCD

SG WTG

▪Potential

misoperation under

IBR due to low

fault current

magnitude & fault

current phase angle

SG

WTG



▪ Dynamic expansion of distance mho characteristic depends on:

– memory polarization method (self/cross/pos. sequence)

– source impedance (SIR)

▪ Under IBR SIR depends on:

1. pre-fault generation (wind speed/solar irradiation)

2. grid strength

▪ Dynamic expansion is varying

▪ Coordination of distance relaying zones is challenging: Increased expansion might cause a distance element to mistakenly see an out-of-zone fault as in-zone.

Impact of Inverter-Based Generation on Line Distance

Protection – Mho Characteristic Dynamic Expansion



Dynamic Expansion Misoperation - Demonstrating Results

Test System▪ Generating Resource Type

– SG

– Type III WTG

– Type IV WTG

▪ Polarization Method

– Self polarized

– Memory cross-polarized

– Memory positive-

sequence-polarized

▪ AG fault



Dynamic Expansion Misoperation - Demonstrating ResultsImpact of IBR Technology

Dynamic Expansion is larger for Type IV WTG



Dynamic Expansion Misoperation - Demonstrating Results

Impact of Polarization Method

Dynamic Expansion

is larger for cross

polarization



Dynamic Expansion Misoperation - Demonstrating ResultsImpact of Wind Speed

The mho circle expansion and the resistive reach change with changing wind speed



• Large levels of inverter-based

resources might impact the rate of

change of the impedance (due to fast

controls) and the impedance trajectory

measured by power swing relays

potentially resulting in:

• Power Swing Blocking (PSB) function

potential misoperation due to faster

power swings under high levels of

IBR – swings misinterpreted as faults

• Out of Step Tripping (OST) function

misoperation due to modified

impedance trajectories under high

levels of IBR

Impact of Inverter-Based Generation on Power Swing Protection



IEEE PSRC-D29 Test System

• Simulated power swing under two scenarios:

• Scenario 1: no wind generation

• Scenario 2: 50% wind generation (synchronous generators 6, 15, and 16 replaced by wind generators)

• Investigated response of relay Maple-Spruce

AB Fault 150ms

Relay Maple-Spruce

G

16

G

15

100 mi

Bus16_Spruce

230kV

Bus15_Elm

230kV

75 mi

Bus8_Maple

230kV

12

-30G

14230/24

Bus14_Maple_U2

24kV

2

3

1

115/230/13.2

Bus9_Maple_TRT

13.2kV

Bus2_Maple

115kV

12

-30G

4115/13.2

Bus4_Maple_U1

50 mi

50 mi

25 m

i

Bus1_Birch

115kV

Bus5_Oak

115kV12

-30G

6115/13.2

Bus6_Oak_U1

13.2kV

15 mi

12

-30G

3115/13.2

Bus3_Birch_U1

13.2kV

50 mi

2

3

1

115/230/13.2

Bus11_Pine_TRT

13.2kV

G

13230/24 Bus13_Pine_U1

24kV

1 2

-30

75 mi

Bus10_Pine

230kV

25 m

i

25 mi

50 mi

Bus12_FIR

230kV

Bus7_Pine

115kV



Demonstrating Results – PSB Misoperation

• The relay successfully detects the power

swing and issues a PSB signal to block

zone 1 and 2 of the distance relay.

No Wind

• Type III WTGs

• PSB misoperation under 50% wind

integration. Relay doesn’t detect the power

swing and fails to block distance protection

zones.

• Reason: measured impedance moves from

the outer element to the middle element in

less than 2 cycles (PSB time-delay) due to

the increased rate of change of impedance

• Swing misinterpreted as fault. Zone 1

instantaneously issues a tripping signal which

results in undesired tripping of Line8_16.

50% Wind



Demonstrating Results – OST Misoperation

• In the wind scenario the impedance

trajectory reversed direction after

crossing the inner element

• Movement of the electrical center

• System Defense Plans:

• Placement of OST relays

• Based on extensive dynamic

simulation studies

• IBR type and controls affect the

impedance trajectory

• Need for protection modeling in planning

studies



Evaluation of Generic Models of Inverter-Based

Resources for Power Swing Protection Studies



Background

• Due to its complexity, power swing protection study is commonly performed using

extensive dynamic simulations.

• Models and simulation tools are well-established for traditional SG-dominated power

systems.

• These traditional models may be inadequate for dynamic studies involving IBRs, due to

fundamental differences in dynamic behavior of IBRs & SGs.

• Necessary to identify IBR modeling requirements for power swing studies.

• Two types of IBR models for dynamic studies:

Electromagnetic transient-type (EMT) models: offer the highest accuracy; however,

computationally demanding for large-scale grids.

Phasor-domain models: provide a quasi-steady state fundamental frequency

representation and less modeling details; however, less computationally demanding and

suitable for initial long-term planning assessment protection studies wherein detailed user

defined models of IBRs and relays may not exist.



Study Objective & Test System

•Power swing scenario: Outage of the line connecting buses 12 to 15 due to a fault on the line.

•Power swing impedance trajectory is calculated by the distance relay R21 on bus 8 looking towards bus 16.

• Objective: Compare the power swing

results of an EMT and a phasor-

domain simulation model with IBRs

• IEEE PSRCC D29 test system

o Replaced SGs with DFIG WTGs

o Modeled in

EMTP (generic library models)

PSS/E (generic WECC models)



• Only SGs, machine saturation not modeled in EMT or Phasor.

• Power swing trajectories largely match, and the key swing characteristics are consistent.

Cross-Examination of EMT & Phasor – Synchronous Generation



• The SG at bus 16 is replaced by a DFIG

(corresponding to 25% wind).

• The key swing characteristics calculated by the two

programs are consistent:

The starting point of the swing

The time of crossing the outer and middle elements

(corresponding to the PSB time delay)

The calculated location of EC

• Some differences, particularly in the initial cycles due

to model differences

• As the swing continues and the initial fast transients

die out, the swing trajectories become more

consistent.

• Both programs correctly show the increased rate of

change of swing impedance trajectory (reduced PSB

delay) due to IBRs.

Cross-Examination of EMT and Phasor - IBR

Generation ScenarioPSB time delay (cycles)

Positive-Sequence Program EMTP

SG 8.1 8.5

25 % IBR 6.4 6.1



• The difference between EMT and phasor becomes more significant as the share of IBRs

increases due to the modeling differences.

• Example: same swing under 50% IBR

Cross-Examination of EMT and Phasor - IBR

Generation ScenarioPSB time delay (cycles)

Positive-Sequence Program EMTP

SG 8.1 8.5

25 % IBR 6.4 6.1

50 % IBR 6.4 4.3



ROCOF Protection

EIRGrid RoCoF 1Hz/s Program

• With decreasing system

inertia RoCoF increases

• Conventional and IBR

generation need to withstand

higher RoCoF– relays settings

need to be adjusted

• Higher RoCoF is more difficult

to measure

• UFLS also affected



Case Studies



NYPA Case Study - Objective & Approach

▪ Objective: Study the protection system performance in an area within NYPA territory with wind generation

▪ Approach:

– Developed an EMT model including wind parks and relay models of the study area

– Cross-examined the fault response results between IBR and SG models

– Reviewed existing protection schemes with associated settings and identified potential protection misoperation cases due to wind parks



EMT Network Model

▪ An EMTP model of the study area was developed

▪ Only buses close to wind park locations are retained. The rest of the network is represented by equivalent circuits.

▪ 6 detailed wind park (WP) models included.



Relay Data

Relay Identifier

Protected Component

Protection Functions

1 XmissionLine

21, 85-21 (POTT), 50P, 51P, 51N, 67N, 87L

2 XmissionLine

21, 85-21 (POTT), 50P, 51P, 51N, 67N, 87L

3 XmissionLine

21, 50G, 51G

4 XmissionLine

21, 50G, 51G p1

p2

Fault

Fault

Midline_Fault

SrSlPOTT

POTT1

Page i2

Page i1

Page v1

Page i1

Page i1Pagev1

Pagev1

CT

2C

T1

VT1

PI

+P

I5

PI

+P

I6

VT5

Page v2

v iir

vr s

t21

68

Generic

21G

21P21

v iir

vr s

t21

68

Generic

21G

21P21_AH

s

ivir

vr

t51

50

67

50_51_6751P-50P

51N

67N

Siemens

tapi1

i2

i3

ig1

ig2

ig3

t87

s

Relay1187

Generic

Pagei2

Pagei1

s

ivir

vr

t51

50

67

50_51_67_R

51P-50P

51N

67N

Siemens

Page i2Pagev2

v iir

vr s

t21

68

Generic

21G

21P21_R

Pagev2 Page i2

Page comm_L1

SrSlPOTT

POTT2

Page comm_L1

Page comm_L2

Page comm_L2

Sub2 230 kV

Sub1 230 kV



Fault Analysis – Type III Wind Park Response

I1

I2

I0

Ia

Ib

Ic



Fault Analysis – Type IV Wind Park Response

I1

I2

I0

Ia

Ib Ic



Wind Park Short-Circuit Results

▪ Short-circuit results using IBR and SG models have been cross-examined.

Fault location If A If B If C If 0 If 1 If 2 Va Vb Vc V0 V1 V2

Sub1 ABG IBR 6000 5700 0 2096 5506 3413 0 0 148.9 70.2 70.2 70.2

Sub1 ABG SG 7200 6850 0 2231 6519 4293 0 0 159 74.9 74.9 74.9

Sub2 ABG IBR 8097 7688 0 2619 7340 4729 0 0 163.7 77.2 77.2 77.2

Sub2 ABG SG 9885 9232 0 2564 8760 6217 0 0 166 77.8 77.8 77.8

Sub3 ABG IBR 8433 7953 0 2607 7601 5005 0 0 146.3 68.9 68.9 68.9

Sub3 ABG SG 10216 9470 0 2770 9051 6306 0 0 164 77.6 77.6 77.6

Sub4 ABG IBR 9280 9290 0 2550 8520 5970 0 0 76.3 35.99 35.99 35.99

Sub4 ABG SG 10956 10893 0 2589 7190 4601 0 0 78 26.01 26.01 26.01



Overcurrent Protection Misoperation

▪ Scenario: Fault current supplied only by WP.

▪ 50P: Ia=1.01pu < Ipkp=3pu: misoperation of 50L_1A

▪ 51N: I0=0.00pu < Ipkp=0.3pu: misoperation of 51N1

• Cause of 50P misoperation is the low fault current contribution of WP.

• Cause of 51N misoperation is the zero-value zero sequence current due to the Delta on the high side of WP transformer.

Misoperation

Misoperation



Distance Protection Misoperation

▪ The fault impedance trajectory falls within zone 1 of both AB and CA elements due to the increased dynamic expansion of mho circle due to the wind parks on a substation.

▪ RYP2_Z1P_AB successfully picks up; however, RYP2_Z1P_CA unintentionally asserts.

RYP2_Z1P_AB

RYP2_ Z1P_CA

RYP2_ Z1P_AB

RYP2_ Z1P_CA



Industry Activities



IEEE PES - NERC Technical Report “Impact of Inverter Based

Generation on Bulk Power System Dynamics and Short-Circuit

Performance”

• Joint IEEE PES and NERC Task Force

• Co-chairs: Kevin Jones (Xcel Energy) & Pouyan Pourbeik (PEACE)

• Published in July 2018

• Chapter 2: “Large System Impact Issues Related to Large

Penetration of Inverter Based Resources”

• Chapter 3: “Protective Relay Issues Related to Large Penetration of

Inverter Based Resources”

• PSRC CTF34 members contributed to the report

• Webinar on April 2nd 2019



PSRCC WG C32 Report

Published!


https://resourcecenter.ieee-pes.org/technical-publications/technical-reports/PES_TP_TR81_PSRC_WGC32_071520.html?utm_source=facebook&utm_medium=social&utm_campaign=tr-80-technical-report


IEEE P2800 Objective



IEEE P2800 Leadership Team



IEEE P2800 Sub-Groups

IEEE P2800 SubGroup Lead (=Officer) Mailing List

I. Overall Document Jens C Boemer [email protected]

II. General Requirements Bob Cummings [email protected]

III. Active Power – Frequency Control Mahesh Morjaria [email protected]

IV. Reactive Power – Voltage Control Wes Baker [email protected]

V. Low Short-Circuit Power Ross Guttromson [email protected]

VI. Power Quality Ross Guttromson [email protected]

VII. Ride-Through Capability Requirements Bob Cummings [email protected]

VIII. Ride-Through Performance Requirements Manish Patel [email protected]

IX. IBR Protection Babak Enayati [email protected]

X. Modeling & Validation, Measurement Data, and Performance Monitoring

Manish Patel [email protected]

XI. Tests and verification requirements Chenhui Niu [email protected]


mailto:[email protected]












DOE Project “Inverter Based Resource (IBR) Negative Sequence

Current (I2) Injection Study”

IBR OEM models

include: Type 3 and

4 wind turbines, and

PV Solar

• Led by Sandia National Lab

• EPRI had an advisory role

• Report

Blue = Pos. Seq. Orange = Neg. Seq. Green = Zero Seq.

Current sequence component magnitudes (SLG fault)


https://www.osti.gov/biblio/1595917-impact-inverter-based-resource-negative-sequence-current-injection-transmission-system-protection


• Convenor: Dr. Farfilho (Brazil)

• Schedule: Start: Aug. 2018 – End: Aug. 2022

CIGRE WG B5.65 “Enhancing Protection System Performance by Optimizing the Response of Inverter-Based Sources”

CIGRE Activities



References

Journal Publications

1.A. Haddadi, I. Kocar, J. Mahseredjian, U. Karaagac, and E. Farantatos, “Negative Sequence Protection Under

Inverter-Based Resources–Challenges and Impact of the German Grid Code,” Electric Power Systems

Research, volume 88, pages 106573, November 2020.

2.A. Haddadi, M. Zhao, I. Kocar, U. Karaagac, K. W. Chan and E. Farantatos, “Impact of Inverter-Based

Resources on Negative Sequence Quantities-Based Protection Elements,” IEEE Transactions on Power

Delivery, DOI: 10.1109/TPWRD.2020.2978075, March 2020.

3.A. Haddadi, I. Kocar, T. Kauffmann, U. Karaagac, E. Farantatos, and J. Mahseredjian, “Field Validation of

Generic Wind Park Models Using Fault Records,” Journal of Modern Power Systems and Clean Energy, volume

7, issue 4, pages 826–836, July 2019.

4.A. Haddadi, I. Kocar, U. Karaagac, H. Gras, and E. Farantatos, “Impact of Wind Generation on Power Swing

Protection,” IEEE Transactions on Power Delivery, volume 34, issue 3, pages 1118–1128, January 2019.

5.T. Kauffmann, U. Karaagac, I. Kocar, S. Jensen, E. Farantatos, A. Haddadi, and J. Mahseredjian, “Short-circuit

model for Type-IV wind turbine generators with decoupled sequence control”, IEEE Transactions on Power

Delivery, DOI: 10.1109/TPWRD.2019.2908686, Apr. 2019

6.T. Kauffmann, U. Karaagac, I. Kocar, S. Jensen, J. Mahseredjian, and E. Farantatos “An accurate Type III wind

turbine generator short circuit model for protection applications”, IEEE Transactions on Power Delivery, vol. 32.

No. 6, Dec 2017



References

Conference Papers

1. A. Haddadi, I. Kocar, J. Mahseredjian, U. Karaagac, and E. Farantatos, “Performance of Phase Comparison

Line Protection Under Inverter-Based Resources and Impact of the German Grid Code,” IEEE Power and

Energy Society General Meeting (PESGM), Montreal, August 2020.

2.A. Haddadi, I. Kocar, J. Mahseredjian, U. Karaagac, and E. Farantatos, “Negative Sequence Protection Under

Inverter-Based Resources–Challenges and Impact of the German Grid Code,” Power Systems Computation

Conference (PSCC), Porto, Portugal, June 2020.

3.A. Haddadi, M. Zhao, I. Kocar, E. Farantatos, and F. Martinez, “Impact of Inverter-Based Resources on Memory-

Polarized Distance and Directional Protective Relay Elements,” Submitted to 2020 North American Power

Symposium (NAPS), Tempe AZ, October 2020.

4.U. Karaagac, T. Kauffmann, I. Kocar, H. Gras, J. Mahseredjian and E. Farantatos, "Phasor domain modeling of

Type IV wind turbine generator for protection studies," Proc. 2015 IEEE PES General Meeting, Denver, CO, 26-

30 July 2015.

5.T. Kauffmann, U. Karaagac, I. Kocar, H. Gras, J. Mahseredjian, and E. Farantatos, “Phasor domain modeling of

Type III wind turbine generator for protection studies,” Proc. IEEE PES General Meeting, Denver, CO, USA, Jul.

2015.



References

EPRI Reports

1.System Protection Guidelines for Systems with Inverter Based Resources: Performance of Line Current

Differential, Phase Comparison, Negative Sequence, Communication-Assisted, and Frequency Protection

Schemes Under Inverter-Based Resources and Impact of German Grid Code, EPRI, Palo Alto, CA, 2019,

3002016196.

2. Impact of Inverter-Based Resources on Power Swing and Rate of Change of Frequency Protection, EPRI, Palo

Alto, CA, 2020, 3002016198.

3. Impact of Inverter-Based Resources on Protection Schemes Based on Negative Sequence Components, EPRI,

Palo Alto, CA, 2019, 3002016197.

4.Protection Guidelines for Systems with High Levels of Inverter Based Resources, Palo Alto, CA: 2018.

3002013635.

5.Short-Circuit Phasor Models of Inverter-Based Resources for Fault Studies - Model Validation Case Studies,

Palo Alto, CA: 2018, 3002013634.

6.Short-Circuit Phasor Models of Converter Based Renewable Energy Resources for Fault Studies , Palo Alto, CA:

2017. 3002010936.



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Modeling Inverter-Based Resources in Short-Circuit Programs

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