IBR Modeling Fundamentals

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IBR Modeling Fundamentals

Songzhe Zhu

WECC MVS WorkshopSeptember 17, 2020

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Outline

• Modeling guideline for all IBRs connecting to transmission and subtransmission– Power Flow Representation– Dynamic Models– Active power – frequency control– Reactive power – voltage control– Fault ride-through

• Solar PV• BESS and Hybrid

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Basics of modeling IBR connecting to transmission and sub-transmission

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Power Flow Representation

• transmission and sub-transmission connected IBR

EQ

1 2 3 4 5

Interconnection Transmission

Line

Substation Transformer

Equivalent Collector System

Equivalent Pad-mounted Transformer

Plant-level Reactive

Compensation (if applicable)

Equivalent Generator

Point of Interconnection

Typical Single-Generator Equivalent Power Flow Representation

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Collector System & IBR Equivalencing

• Equivalent impedance of the collector system shall be represented – Inverters respond to the terminal voltage– Voltage at POI and terminals are quite different

• Multi-generator representation may be needed– Multiple main GSUs, with separate collectors behind them– Significantly diverse impedances behind different feeders– Inverters by different manufacturers are installed behind the

feeders and these inverters have different control and protection settings

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Multi-Generator Representation

G1

1 2 3 4 5


Line




Equivalent Generator 1


G2

6 7 8Equivalent

Generator 2

Equivalent Generator 3G3

9

Illustrative Multi-Generator Equivalent Power Flow Representation

* Although not illustrated by this example, all var devices should be modeled explicitly.

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Positive Sequence Dynamic Models

• Generic models approved by WECC

• Very flexible to model different control setups

• Models are supported and benchmarked among different software platforms

• Easy access to model documents and user guides

• Generally applicable for systems with a short circuit ratio of 3 and higher at the point of interconnection

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Generic Dynamic Models

Description Model Name Applicability NotesConverter REGC_A

REGC_BREGC_C

All IBR: current source modelAll IBR: voltage source modelAll IBR: REGC_B plus PLL and inner current control loops

Electrical controlREEC_AREEC_CREEC_D

Type 3 and 4 WTG, solar PV Battery energy storageEnhanced model for all types of IBR

Plant controller

REPC_AREPC_BREPC_C

For controlling single deviceFor controlling multiple devicesEnhanced model for controlling singledevice

Ride-through protection LHVRTLHFRT

Voltage ride-throughFrequency ride-through

Enhanced model approved or under development

* Models specific to WTGs are discussed in wind plant modeling session.

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Generic Model Structure

REPC REEC REGCQ/V reference

P reference

iq command

ip command

Network Interface

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Scaling for the Equivalent Generator Size

• Pmax and MVA base in the power flow model and dynamic models are aggregated values

• Power flow model –– MVA base is the sum of the individual MVA rating of the inverters– Pmax is the maximum active power output from the equivalent

generator in accordance with the generation interconnection study and interconnection agreement

• often lower than the sum of the individual rated MW of the inverters due to the practice of oversizing inverters

• Dynamic models –– Model parameters are expressed in per unit of the MVA base for

the model– Typically MVA base matches the MVA base in the power flow

model

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Active Power – Frequency Control Options

• Power flow model: base load flag (BL)– BL = 0: Pgen can be dispatched downward and upward– BL = 1: Pgen can be dispatched downward only– BL = 2: Pgen is fixed

• Dynamic model: REPC– frqflag= 0/1: frequency response no/yes– ddn & dup: downward & upward regulation gain– fdbd1 (+) & fdbd2 (-): over- and under-frequency deadband for

frequency response (pu)

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Active Power – Frequency Control Options (Cont’d)

• With earlier version of the models (prior to Aug 2020)– base load flag is not used in the dynamic simulation– block frequency response through frqflag/ddn/dup

• With model enhancement– Base load flag is used to block frequency response in reec and repc

models except for repc_b.

Functionality BL frqflag ddn dup

No response 2 0 - -

Down regulation only 1 1 >0 0

Up and down regulation 0 1 >0 >0

Functionality BL frqflag ddn dup

No response 2 - - -

Down regulation only 1 1 >0 -

Up and down regulation 0 1 >0 >0

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Active Power – Frequency Control Key Parameters

• Other control parameters in REPC for frequency response– Kpg: proportional gain– Kpi: integral gain– Tlag: lag time constant

Non-step deadband

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Reactive Capacity Requirement

• Interconnection requirement for IBR reactive capacity has evolved, e.g.– No requirement– 0.95 power factor at POI– FERC Order No. 827: 0.95 power factor (dynamic var)

at high side of the substation transformer• The modeling recommendation in this presentation

focuses on IBR complying with FERC Order No. 827

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Model IBR Reactive Capability

• Inverter P-Q capability– Manufacturer provides P-Q capability curves under different ambient

temperatures and DC voltages– Use the P-Q capability curves to verify if there is sufficient capability to

meet the interconnection requirement

• Generator reactive capability in the power flow model– Model the required reactive capability– Qmax and Qmin of the equivalent generator are reactive capability at

Pmax, limited by the minimum amount to meet the interconnection requirement

• Generator reactive capability in the dynamic models– The physical capability is modeled, not limited by the PF requirement

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Reactive Power – Voltage Control in Power Flow

Assuming the only dynamic var sources are inverters –• If inverters regulating voltage at point of measuring (POM)

– Voltage regulation bus is the high-side bus of the GSU– The Generator is set to cont_mode = 2 with pf = 0.95, i.e. the power

flow solution will try to hold voltage at the regulated bus constant within Q limits specified by pf

• If inverters regulating terminal voltage– The Generator is set to cont_mode = -2 with pf ≤ 0.95, i.e. the

power flow solution will try to hold terminal voltage constant within Q limits specified by pf

• Voltage regulation of LTC transformers• Controlled shunts – SVD

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Power Flow Modeling Limitation on Reactive Power / Voltage Control Coordination

• Reactive power – voltage control is coordinated by the power plant controller (PPC)

• Inverter reactive output is controlled along a voltage droop curve

• Most power flow softwares do not currently model PPC and can’t do voltage droop control– PPC power flow model is under development. WECC MVS has

published the model specification.

• Discuss more on PPC control in the hybrid plant modeling session.

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Reactive Power – Voltage Control in Dynamic Models

• Different voltage control options are modeled by the combination of pfflag, vflag and qflag in reec model and refflag in repc model

Functionality PfFlag Vflag Qflag RefFlag

Constant local PF control 1 N/A 0 N/A

Constant local Q control 0 N/A 0 N/A

Local V control 0 0 1 N/A

Local coordinated V/Q control 0/1 1 1 N/A

Plant level Q control 0 N/A 0 0

Plant level V control 0 N/A 0 1Plant level Q control + local coordinated V/Q control 0 1 1 0

Plant level V control + local coordinated V/Q control 0 1 1 1

Plant level PF control* 0 N/A 0 2Plant level PF control + local coordinated V/Q control* 0 1 1 2

* repc_b only

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Plant Level Reactive Power – Voltage Control Options

• Voltage Control: RefFlg=1– Select the regulating bus (Vreg)– Set the monitored branch– Set VcmpFlg=1 if using line

drop compensation (Rc and Xc) – Set VcmpFlg=0 if using reactive

droop (Kc)

• Constant Q Control: RefFlg=0– Select the monitored branch

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Multiple Device Plant Control: REPC_B

Plant PF Control Multiple Device Control

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Plant Level Reactive Power – Voltage Control Key Parameters

• Key parameters– Control deadband (dbd)– Input (emax/emin) and output (qmax/qmin) limits– Control gains (kp/ki)– Intentional phase lead (Tft)– Communication lag (Tfv)– Voltage threshold to freeze plant voltage integral control (vfrz)

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Inverter Level Reactive Power – Voltage Control Options

PF Control

Constant Q Control

If no plant controller –

Local V Control

Local Coordinated Q/V Control

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Inverter Level Reactive Power – Voltage Control Options (Cont.)

Plant level Q or V Control

If coordinated with plant controller –

Plant level Q or V Control and Local Coordinated Q/V Control

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Inverter Level Reactive Power – Voltage Control during Voltage Dip

• Voltage dip: Vt < Vdip or Vt > Vup• During voltage dip, local Q control and local V control

freeze• K-factor control: proportional gain Kqv

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Coordinate Plant Level and Inverter Level Controls

• Key factors to achieve desired control performance –– Choose control option: plant level control or plant level control

and local coordinated control– At what voltage levels, freeze plant level Q/V control (vfrz) and

local Q/V control (vdip), taking into account plant controller regulates POM bus voltage while the inverter controller regulates terminal bus voltage

– At what voltage levels, k-factor control shall be activated– Control gains and time constant associated with each control

mode– P/Q priority

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Inverter Current Limit

iq control

ip control

Ip and Iq control come together

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Invert Current Limit (Cont.)

• Define the maximum inverter current imax

• REEC_A: voltage-dependent current limits for ip and iq separately (VDL1 and VDL2)

• Total current 𝑖𝑖𝑝𝑝2 + 𝑖𝑖𝑞𝑞2 is

limited by imax

• During low voltage, ipcmd or iqcmd may be reduced until the voltage recovers depending on P/Q priority

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P-Q Priority

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Example of Different Control Strategies

Vdip=0.9, Kqv = 2.0

Vt at fault is below 0.25.Iqcmd rises quickly to 1.07.

After fault, initial Vt is 1.196.

Plant control freezes for voltage outside [0.9,1.1]. Iqcmd reduces immediately post fault.

Kvi = 40 & plant control

Vt at fault is below 0.25.Iqcmd rises quickly to 1.3.

After fault, initial Vt is 1.2.

Slower plant control keeps voltage at 1.2 for about 0.13 sec.

Control Setup 2: enable voltage dip and kqv controlControl Setup 1: slow plant control and no voltage dip and kqv control

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Frequency Ride-through

• Lhfrt model parameters should reflect the actual frequency protective relay settings

• The settings should be PRC-024 compliant• Frequency calculation in positive sequence stability programs are

not accurate during and immediately following the fault• Work-around of false frequency tripping for a close-by simulated

fault –– Use lhfrt in “alarm only” mode and analyze each individual alarms– Disable frequency tripping under low voltage condition (dypar[0].v_f_inh

in javaini.p)– Do not set instantaneous tripping and always include some delay for

frequency tripping

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Voltage Ride-through

• Lhvrt model parameters should reflect the actual voltage protective relay settings

• The settings should be PRC-024 compliant– PRC-024 requirement is set with voltage at the high side of the

substation transformer (POM)– The actual protection is set with terminal voltage– The voltage setpoints should take into account the difference between

inverter terminals and POM

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Modeling solar PV plants connecting to transmission and sub-transmission

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Model Solar PV Momentary Cessation

• Model structure: REGC, REEC_D, REPC• Modeling elements

– Current reduction during cessation [REEC_D].VDLq and VDLp• set current limits to 0 for both ip and iq when the voltage is below Vmc-lv or

above Vmc-hv

– Disable low voltage power logic [REGC].lvplsw = 0– Ramp control [REGC].rrpwr, iqrmax and iqrmin– P/Q priority during recovery [REEC_D].pqflag– Voltage dip logic [REEC_D].vblkl = Vmc-lv, vblkh = Vmc-hv

– Current recovery delay [REEC_D].Tblk_delay

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Comparison of REEC_D with REEC_A for Modeling Momentary Cessation

• REED_D has the full capability of modeling momentary cessation, while REEC_A does not.

REEC_A REEC_DMC low voltage threshold vdip vblklMC high voltage threshold vup vblkhVoltage-dependent reactive current limit*

VDL14 pairs of (vq, iq)

VDLq10 pairs of (vq, iq)

Voltage-dependent reactive current limit*

VDL24 pairs of (vp,ip)

VDLp10 pairs of (vp, ip)

Active current recovery delay Thld2 Tblk_delayReactive current recovery delay Not modeled Tblk_delay

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REEC_D Model Enhancement

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Converting REEC_B to REEC_D

• REEC_D is an expansion of REEC_B. If the solar PV inverters do not use momentary cessation, the previous REEC_B models can be easily converted to REEC_D by adding parameters in this table.

Parameter Name Value

rc 0Xc 0Tr1 0Kc 0Vcmpflag 0Ke 0Iqfrz 0Thld 0VDLq (-1.0, imax), (2, imax), (0,0) …VDLp (-1.0, imax), (2, imax), (0,0) …vblkl 0vblkh 2Tblk_delay 0iqfrz 0thld 0thld2 0vref1 0pflag 0

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Modeling BESS and hybrid power plants connecting to transmission and sub-

transmission

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Definition of Hybrid Power Plant

• A generating resource that is comprised of multiple generation technologies that are controlled by a single entity and operated as a single resource behind a single point of interconnection (POI).

• Single point control of multiple generators is the key that requires additional modeling capability.

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Two Types of Configuration

DC-Coupled AC-Coupled

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BESS Plant and DC-Coupled Hybrid Plant – Power Flow Model

• DC-coupled hybrid plant is modeled the same way as a BESS only plant

• Batteries and solar PV arrays on the DC side are modeled in a single generator

• Pmin in the power flow model represents the maximum charging power – For stand-alone BESS, pmin < 0;– For hybrid, pmin <0 if charging from the grid; pmin = 0

if DC-side charging only.

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BESS Plant and DC-Coupled Hybrid Plant – Dynamic Model

• Use the second generation RES models: regc, reec_c or reec_d, repc

• Reec_c includes simulation of the state of charge

• Reec_d does not have the state of charge logic any more.

Common simulation set-up mistake: PGEN < 0 and SOCini = 1.0; PGEN > 0 and SOCini = 0

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AC-Coupled Hybrid Plant

• Different technologies are modeled by separate generators

• Single point control needs to be implemented in both the power flow model and the dynamic model – Power Plant Controller (PPC) power flow model is

being developed– Repc_b has been enhanced for better hybrid

frequency response control

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Modeling Requirement for AC-Coupled Plant

• Frequency / active power control– The total MW injection at the point of interconnection is limited

by the contractual maximum– Different components have different frequency response

• Voltage / reactive power control– Plant reactive output limit is typically 0.95 power factor at the

high side of substation transformer– Power plant controller coordinates operation of the inverters,

transformer tap changers, SVDs, and other var devices to maintain the regulated bus voltage within a deadband from the voltage schedule

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Proposed PPC Power Flow Model

• A PPC model is defined by:– Individual devices such as generators, SVDs, and

other controllable reactive devices*– A regulated bus– QV characteristics at the regulated bus– Plant real power limits

*Transformers that control tap will not be part of the PPC

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PPC QV Characteristics

• The power flow solution represents an operating point such that the Mvar being injected at the Regulated Bus from the devices in the PPC will follow a QV characteristic with a deadband.– For example, Qdb is 0 or equal to the var losses on the gen-tie;

qmax and qmin represents 0.95 lag/lead power factor at the regulated bus

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Real Power Monitoring

• The PPC model monitors the real power injection at the monitored bus and generate warning messages if the injection is outside the plant real power limits.

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An Example of PPC Model

PV

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Equivalent Generator for

Solar PV


BT

6 7 8 Equivalent Generator for

Battery

230kV 34.5kV 690V

SVD“SD”

T1

T2

PPC: Solar-BESSDevices Device Type

Bus 5 "PV" GeneratorBus 8 "BT" GeneratorBus 3 "SD" SVDReactive Power ControlRegulated Bus Bus 2Qmax (Mvar) 34Qmin (Mvar) -34Real Power MonitorMonitored MW At Bus 1 from Bus 2 Pmax 100Pmin -100

100 MW

100 MW

QV Curve at Bus 2

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Dynamic Model for AC-Coupled Hybrid

• Use regc, reec and repc_b modules.

Module PSLF modules PSSE modules

BESS Component

Grid interface regc_* REGC*Electricalcontrols

reec_c or reec_d

REECC1 or REECD1

Non-BESS Component Use appropriate modules for the gen type

Plant controller repc_b PLNTBU1Aux control REAX4BU1 or

REAX3BU1Voltage/frequency protection lhvrt/lhfrt VRGTPA/FRQTPA

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More on REPC_B

• Invocation notes– In PSLF implementation, REPC_B is invoked from one of generators in the plant.

It is important to have REPC_B invoked from an online generator. – The regulated bus and the monitored branch must be specified for REPC_B.

• Reactive control– Qmax and qmin are plant level reactive limits; on the system MVA base in PSLF

implementation

• Frequency control– Set frqflag to enable plant level frequency response– Use base load flag to enable or block individual component response

Component BaseLoad flag ModuleSolar PV - Frequency response, down only regulation

1 reec_d

BESS - Frequency response, up and down

0 reec_c or reec_d

Plant controller Repc_b withFrqflag=1, dup > 0, ddn > 0

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Reference

• WECC MVS, Solar PV Plant Modeling and Validation Guidelinehttps://www.wecc.org/Reliability/Solar%20PV%20Plant%20Modeling%20and%20Validation%20Guidline.pdf• Pouyan Pourbeik, Memo RES Modeling Updates 083120_Rev17https://www.wecc.org/Administrative/Memo_RES_Modeling_Updates_083120_Rev17_Clean.pdf• WECC MVS, Converting REEC_B to REEC_A/Dhttps://www.wecc.org/Reliability/WECC%20White%20Paper%20on%20Converting%20REEC%20rev202008.pdf• WEC MVS, Hybrid Plant Modeling Enhancementhttps://www.wecc.org/_layouts/15/WopiFrame.aspx?sourcedoc=/Administrative/WECC%20White%20Paper%20on%20modeling%20hybrid%20solar-battery.pdf

https://www.wecc.org/Reliability/Solar%20PV%20Plant%20Modeling%20and%20Validation%20Guidline.pdf

https://www.wecc.org/Administrative/Memo_RES_Modeling_Updates_083120_Rev17_Clean.pdf

https://www.wecc.org/Reliability/WECC%20White%20Paper%20on%20Converting%20REEC%20rev202008.pdf

https://www.wecc.org/_layouts/15/WopiFrame.aspx?sourcedoc=/Administrative/WECC%20White%20Paper%20on%20modeling%20hybrid%20solar-battery.pdf

IBR Modeling Fundamentals

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