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1
Use of the new revisions of IEEE
Standards 421.2 and 421.5 to satisfy
international grid code requirements
Presented by: Les Hajagos
Kestrel Power Engineering - Canada
[email protected]
2
Introduction
• In North America, we have the NERC Reliability
Standards in place. In other regions around the world,
local grid codes have similar requirements.
• The Excitation System SC will report on our many
recent activities related to testing and modeling of
excitation systems, associated controllers and limits to
support meeting these requirements
• See also our companion presentation 16PESGM2680
‘“The Impact of Grid Codes Upon Generator Excitation System
Design and Standards”
3
Presentations
Presentation
421.2 Guide for Identification, Testing and
Evaluation of Dynamic Performance
421.5 Recommended Practice for Models for
Power System Stability Studies
Overview of grid codes
Practical international experiences
421.5 sample data and model data usability
Testing model data usability
Power System Stabilizer tuning criteria
Excitation limiter models and protection
coordination
Presenter
Organization
Rich Schaeffer
Basler Electric
Les Hajagos
Kestrel Power
Robert ThorntonBrush Electric
Jones
José Taborda
JT Consulting
Quanta
Alex Schneider
Technology
Leo Lima
Kestrel Power
Bureau of
Shawn Patterson
Reclamation
Les Hajagos
Kestrel Power
4
IEEE 421 Series of Standards
• 421.1 Standard Definitions
• 421.2 Guide for Identification, Testing and Evaluation
of Dynamic Performance
• 421.3 High-Potential Test Requirements
• 421.4 Guide for Preparation of Specifications
• 421.5 Recommended Practice for Models for Power
System Stability Studies
• 421.6 Specification and Design of Field Discharge
Equipment
5
NERC Standards (Excitation Related)
• MOD-025-2, Verification and Data Reporting of Generator
Real and Reactive Power Capability and Synchronous
Condenser Reactive Power Capability
• MOD-026-1, Verifications of Models and Data for Generator
Excitation Control System or Plant Volt/Var Control Functions
• VAR-002-4, Generator Operation for Maintaining Network
Voltage Schedules (includes AVR/PSS requirements)
6
NERC Standards (Excitation Related)
• PRC-005-2 Protection System Maintenance – may impact new
exciters with built in protection
• PRC-019-2 Coordination of Generating Unit or Plant
Capabilities, Voltage Regulating Controls, and Protection
• PRC-024-1 Generator Performance During Frequency and
Voltage Excursions
7
NERC MOD-026-1 Verifications of Models and
Data for Generator Excitation Systems
Items to be verified by measurement and reported are:
•
manufacturer and type of excitation system (e.g. static, brushless, rotating dc, etc.)
•
model for each excitation system / voltage regulator control system with associated
gains, time constants, and limits
•
static set points for under and over excitation limiters
•
reactive compensator settings
•
Measured data showing match between measurement and simulations
•
model for each power system stabilizer with associated gains, time constants, and limits
•
Associated generator model
8
Example Grid Code Excitation Response Requirements
Each synchronous generation facility that is rated at 10 MVA or
larger shall be equipped with an excitation system with
• A voltage response time to either ceiling not more than 50ms
for a 5% step change from rated voltage under open-circuit
conditions and;
• A linear response between ceilings
• Positive and negative ceilings not less than 200% and -140% of
rated field voltage at rated terminal voltage and rated field
current
• A positive ceiling not less than 170% of rated field voltage at
rated terminal voltage and 160% of rated field current
9
421.5 Recommended Practice for Models
for Power System Stability Studies
• This IEEE standard started in 1968 with papers describing
simulation models following the initial creation of NERC and
the use of digital simulation programs to study and operate
power systems
• It includes the necessary simulation models of the excitation
system major control functions: AVR, RCC, PSS and the new
2016 revision includes models of OEL, UEL and SCL functions
and PF/Var controllers and most importantly linkages of the
limiters to the AVR
10
421.5 Excitation System Classifications
• Three distinctive types of excitation systems are
identified on the basis of excitation power source:
• a) Type DC Excitation Systems, which utilize a direct
current generator with a commutator
• b) Type AC Excitation Systems, which use an
alternator and either stationary or rotating rectifiers
to produce the direct field current
• c) Type ST Excitation Systems, in which excitation
power is supplied through transformers or auxiliary
generator windings and rectifiers
11
Summary of Changes and Equivalence of Models
Model Name
Example DC Rotating Exciters
Version of IEEE Std.
421.5
2015 2005 1992
DC1C DC1A DC1A Additional options for connecting OEL limits and
additional limit VEmin
DC2C DC2A DC2A Additional options for connecting OEL limits and
additional limit VEmin
DC3A DC3A DC3A no changes
DC4C DC4B
n/a Additional options for connecting OEL and UEL inputs
12
Additional Excitation System Functions
•
•
•
•
•
•
•
Voltage sensing and load compensation
Power system stabilizer
Over-excitation limiter
Under-excitation limiter
Stator current limiter
Power factor and var control
Discontinuous excitation controls
13
Functional Block Diagram for Synchronous
Machine Excitation Control System
(VSCLsum) or
(VSCLoel and VSCLuel)
Vpf/VAr
VUEL
VC
VOEL
STATOR
CURRENT
LIMITER
P, Q, V, I
Q, pf
PF/VAr
CONTROLLER
P, Q, V, I
UNDEREXCITATION
LIMITER
VOLTAGE
MEASUREMENT
TRANSDUCER
VC1
CURRENT
COMPENSATOR
V, I
OVEREXCITATION
LIMITER
VFE
EXCITATION
CONTROL
ELEMENTS
EFD
SYNCHRONOUS
MACHINE AND
POWER SYSTEM
EXCITER
EFE
IFD
VREF
VS
VST
DISCONTINUOUS
EXCITATION
CONTROL
POWER SYSTEM
STABILIZER
VSI
14
Type DC1C DC Commutator Exciter
VOEL
VUEL
VOEL
a
b
b
VUEL
a
VREF
VC –
VRmax
+
+
S
+
+
VS
+
+
S
1+sTC
HV
gate
1+sTB
–
LV
gate
EFE
KA
1+sTA
VRmin
VSCLsum
a
a
VUELscl
VOELscl
b
b
+
1
S
sTE
–
EFDmin
VFE
S
VF
EFD
+
+
VX
KE
SE(EFD)
(a)
sKF
1+sTF
alternate
OEL input
locations
(VOEL)
a
summation point
b
take-over
footnotes:
(a)
VX = EFD∙SE(EFD)
alternate
UEL input
locations
(VUEL)
a
summation point
b
take-over
alternate
SCL input
locations
(VSCL)
a
summation point
b
take-over
15
Type PSS2C Power System Stabilizer Model
VSI1max
VSI1
VSTmax
sTW1
sTW2
1
1+sTW1
1+sTW2
1+sT6
+
S
+
VSI1min
sTW3
u1
1+sTW3
sTW4
VSI2min
(1+sT9)M
N
+
S
–
KS1
1+sT1
1+sT3
1+sT10
1+sT12
1+sT2
1+sT4
1+sT11
1+sT13
VPSS
VSTmin
KS3
VSI2max
VSI2
1+sT8
1+sTW4
u2
block
bypass
logic
(a)
y
KS2
1+sT7
7 PSS types available
Inputs to all excitation types
PSS
VST
output
logic
(b)
16
Sample Data for PSS2C Stabilizer (for AC6C Model)
Description
Power system stabilizer gain
Power system stabilizer gain
Power system stabilizer gain
PSS transducer time constant
PSS transducer time constant [3]
PSS washout time constant
PSS washout time constant
PSS washout time constant
PSS washout time constant
PSS ramp tracking filter numerator time constant
PSS ramp tracking filter denominator time constant
PSS ramp track filter denominator exponent
PSS ramp track filter numerator exponent
PSS numerator (lead) compensating time constant (1st block)
PSS denominator (lag) compensating time constant (1st block)
PSS numerator (lead) compensating time constant (2nd block)
PSS denominator (lag) compensating time constant (2nd block)
PSS numerator (lead) compensating time constant (3rd block)
PSS denominator (lag) compensating time constant (3rd block)
PSS numerator (lead) compensating time constant (4th block)
PSS denominator (lag) compensating time constant (4th block)
Maximum PSS output
Minimum PSS output
Input signal #1 maximum limit
Input signal #1 minimum limit
Input signal #2 maximum limit
Input signal #2 minimum limit
Generator MW threshold for PSS activation
Generator MW threshold for PSS de-activation
Symbol
KS1
KS2
KS3
T6
T7
Tw1
Tw2
Tw3
Tw4
T8
T9
M
N
T1
T2
T3
T4
T10
T11
T12
T13
VSTmax
VSTmin
VSI1max
VSI1min
VSI2max
VSI2min
PPSSon
PPSSoff
Type
A
E/A
E
E
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
Value
20
[2]
1
0.0
10
10
10
10
[4]
0.30
0.15
2
4
0.16
0.02
0.16
0.02
[5]
[5]
[6]
[6]
0.20
–0.066
2
-2
2
-2
0
0
Units
pu
pu
pu
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
s
pu
pu
pu
pu
pu
pu
pu
pu
17
OEL
activation
logic
Ibias
VOELmax3
+
S
(a)
–
Ex: OEL2C
Ierr
(b)
KPoel+
KIoel
+
s
+
VOELmax2
sKDoel
1+sTC2oel
1+sTC1oel
1+sTDoel
1+sTB2oel
1+sTB1oel
VOELmin3
Iact
VOELmax1
VOELmin2
VOEL
VOELmin1
TFCL
Iinst
KACT
1
1
1+sTAoel
OEL
input
5 types of OEL
(d)
KSCALE
Ipu
Summation and
takeover styles
Z
Ilim
Tlim
VINVmax
Tmax
W
K2[(Ipu/ITFpu)c2−1]
IERRinv2
–
IERRinv1
K1[(Ipu/ITFpu) −1]
ITFpu
S
(f)
c1
1+sTRoel
(e)
s
Iref
+
Terr
OEL
ramp rate
logic
OEL
timer
logic
VINVmin
+
1
S
s
–
(c)
Tmin
KFB
footnotes:
Inputs to all
excitation types
(a)
OEL activation logic uses user-selected parameters Ten, Toff, ITHoff, Ireset
and Iinst. It also uses the signals Terr, Iact and Iref shown in the block
diagram.
IF {(Terr ≤ 0) or [(Iact > Iref) for longer than Ten]} or (Ten =0)
enable OEL à Ibias = 0
IF {(Iref = Iinst) and [(Iref – Iact) > ITHoff} for longer than Toff
reset OEL à Ibias = Ireset
(b)
(c)
The OEL transfer function is either just the gain KPoel, or the PID control,
or the double lead-lag blocks. The parameters in the model should be set
accordingly.
OEL timer logic uses user-selected parameters FixedRU, FixedRD and
ITFpu. It also uses the signals Ipu and IERRinv2, shown in the block diagram.
IF (ITFpu − Ipu) ≥ 0
W = FixedRU + IERRinv2
ELSE
W = FixedRD + IERRinv2
ENDIF
(d)
OEL input is user-selected. Could be generator field current IFD or
generator field voltage EFD or exciter field current VFE.
(e) Parameter KSCALE should be calculated to convert from the per unit base
used for the OEL input signal to a per unit base corresponding to the
rated value for the selected OEL input signal. All other parameters in the
model are expressed in per unit of rated value.
(f) OEL ramp rate logic uses user-selected parameters SW1, KZRU, TFCL, KRU
and KRD. It also uses the signals Terr and IERRinv1, shown in the block
diagram. The parameter SW1 is a user-selected logic, which will select
fixed ramp rates or a ramp rate function of the field current error.
IF
SW1 = 0
C = KRU
D = KRD
ELSE
C = IERRinv1
D = IERRinv1
ENDIF
IF Terr ≥ Kzru*TFCL
Z=C
ELSEIF Terr ≤ 0
Z=D
ELSE
Z=0
ENDIF
(fixed ramp rates)
(ramp Iref up)
(ramp Iref down)
18
2 UEL types
inputs to all excitation types
summation and takeover styles
VURmax
VUR
–
–
y1=|KUC∙VT−j∙IT|
VUImax
–
y1
VUC +
–
IT
S
VUerr
KUL+
–
VUImin
VF
VUF
KUF
VUImax
KUI
1+sTU1
1+sTU3
s
1+sTU2
1+sTU4
VUEL
Q (pu)
VUImin
ra d
ius
=K
UR
Vars
out (+)
normalized limit function
specified for VT = 1 pu
PT
QT
VUCmax
–
VT
Center = KUC
y2
KUR - KUC
–
y2=|KUR∙VT|
op.
point
UEL not
limiting
P (pu)
Vars
in (−)
UEL
limiting
19
overexcited range
VSCLmax
LV
gate
1
1+sTIT
y = (u)
u
inputs to all
excitation types
1
1
1+sTQSCL
+
–
S
–
1+sTINV
+
–
S
+
S
ISCLerr
ISCLinv
IQmin
–
S
KPoex+
B
KIoex
s
y
ISCLlim –
IQ
A
Ioex2
K
delayed reactive
power logic
2 SCL types
IT
Ioex1
SW1
(b)
0
S
+
SW1
VSCLmax
(b)
B
KPuex+
A
KIuex
s
Iuex1
VSCLmin
0
underexcited range
footnotes:
summation and
takeover styles
–
(c)
Iuex2
LV
gate
VSCLmin
(a)
The reactive current IQ is defined in this model as the reactive power output of the generator (QT) divided
by the magnitude of the terminal voltage (VT). In other words, IQ is positive for over-excited operation.
(b)
SW1 is a user-selected option. When position A is selected, the SCL response is derived from the
reactive current. When position B is selected, the SCL response is derived from reactive power.
(c)
The delayed reactive power logic uses user-selected parameters SW2, TDSCL and VSCLdb. It also uses the
signals ISCLerr and ISCLinv shown in the block diagram, and the generator reactive power output QT:
IF [(SW2 = 0) and (ISCLerr > 0 for longer than TDSCL)] or [(SW2 ≠ 0) and (ISCLinv > 0)] THEN
IF QT > VSCLdb THEN
Ioex2 = ISCLerr
Iuex2 = 0
ELSEIF QT < −VSCLdb THEN
Ioex2 = 0
Iuex2 = ISCLerr
ELSE
Ioex2 = 0
Iuex2 = 0
ENDIF
ELSE
Ioex2 = 0
Iuex2 = 0
ENDIF
VSCL
20
2 PF and VAR types
PFREFnorm
(b)
+
S
PFerr
–
PFnorm
VT
IT
VPFLMT
pf
controller
logic
Verr
KPpf +
(c)
KIpf
s
VPF
(a)
−VPFLMT
footnotes:
(a) The output of the model (VPF) is an incremental variable that should be added
to the voltage reference setpoint (VREF) in the excitation system model.
(b) The signal PFnorm is the normalized power factor of the machine, while
PFREFnorm is the desired (reference) setpoint, using the same normalization as
PFnorm.
(c) The PF controller logic uses user-selected parameters VITmin, VVTmin, and VVTmax.
It also requires the signals PFerr and the magnitudes of the generator terminal
voltage (VT) and current (IT). The logic also depends on the status of the
excitation limiters, OEL, UEL and/or SCL.
Verr = 0
IF
OEL and UEL and SCL are inactive
IF (IT > VITmin) and (VT > VVTmin) and (VT < VVTmax)
Verr = PFerr
ENDIF
ENDIF
21
Per Unit System
•
•
•
•
Generator Stator Quantities
Generator Field Quantities
Exciter Field Quantities
Saturation (Generator and Rotating Exciter)
22
Manufacturer Model Cross Reference
ST1C
Silcomatic (a trademark of Canadian General Electric Co.). Westinghouse Canada Solid State
Thyristor Excitation System; Westinghouse Type PS Static Excitation System with Type WTA,
WTA-300 and WHS voltage regulators. Static excitation systems by ALSTOM, ASEA, Brown
Boveri, GEC-Eliott, Hitachi, Mitsubishi, Rayrolle-Parsons, and Toshiba. General Electric
Potential Source Static Excitation System. Basler Model SSE/SSE-N. UNITROL (a registered
trademark of Asea Brown Boveri, Inc.); THYRIPOL (a registered trademark of Siemens AG.);
Westinghouse WDR and MGR, REIVAX static excitation systems.
ST2C
General Electric static excitation systems, frequently referred to as the SCT-PPT or SCPT.
ST3C
General Electric Compound Power Source and Potential Power Source GENERREX excitation
systems (GENERREX is a trademark of General Electric Co.)
ST4C
Basler DECS applied to static excitation, Brush PRISMIC applied to static excitation, General
Electric EX2000/2100/2100e bus fed potential source and static compound source and
GENERREX-PPS or GENERREX-CPS; Canadian General Electric SILCOmatic 5, Basler/Eaton
Cutler-Hammer ECS2100 static excitation system, Andritz Hydro THYNE applied to static
excitation, Emerson/Emerson Ovation DGC or REIVAX static excitation systems.
ST5C
UNITROL D, P, F, and 5000 (trademarks of Asea Brown Boveri); Brush DCP.
ST6C
THYRIPOL (a trademark of Siemens AG) and Basler/Eaton Cutler-Hammer ECS2100 static
excitation systems.
ST7C
ALSTOM excitation systems Eurorec, Microrec K4.1, ALSPA P320 (ALSPA P320 is a trademark
of ALSTOM), ControGen HX.
ST8C
ST9C
ST10C
Andritz Hydro THYNE applied to static excitation
GE Power Conversion SEMIPOL
UNITROL F, 5000, 6080, 6800 (trademarks of Asea Brown Boveri) applied to static excitation
23
Example References and Bibliography
• 421 series of standards
• IEEE Std. C50.13 Synchronous Generators
• IEEE 115 Guide for Test Procedures for
Synchronous Machines
• IEEE 1110 Guide for Synchronous Generator
Modeling Practices
• IEEE 09TP250 Tutorial Course on Power
System Stabilization via Excitation Control
1
Use of the new revision of IEEE
Standard 421.2 to satisfy
international grid code requirements
Presented by: Rich Schaefer
Basler Electric - USA
[email protected]
2
421.2 Purpose
• Provide a basis for evaluating the closed loop
performance of excitation control systems
• Confirm the adequacy of mathematical
models for excitation control systems for use
in analytical studies of power systems
3
NERC MOD-026-1 Verifications of Models and
Data for Generator Excitation Systems
Items to be verified by measurement and reported are:
•
manufacturer and type of excitation system (e.g. static, brushless, rotating dc, etc.)
•
model for each excitation system/voltage regulator control system with associated
gains, time constants, and limits
•
static set points for under and over excitation limiters
•
reactive compensator settings
•
Measured data showing match between measurement and simulations
•
•
model for each power system stabilizer with associated gains, time constants, and limits
Associated generator model
4
421.2 Guide for Identification, Field Testing
and Evaluation of Dynamic Performance
NERC MOD 026 requires simulation models validated by
test results of excitation system controls including:
•Automatic voltage regulator- Small Signal Response
•Reactive current compensation- Reactive Droop
•Excitation Limiter Validation- Specific dynamic
performance requirements
•Power System Stabilizer Tuning- Frequency Response
5
421.2 Dynamic performance classifications
Large signal performance criteria
• Ceiling current and voltage
• Voltage response time
• High initial response
Small signal performance
• Frequency response characteristics
• Stability/Stabilizers
Effects of excitation limiters
6
Example Grid Code Excitation Response Requirements
Each synchronous generation facility that is rated at 10 MVA or
larger shall be equipped with an excitation system with
• A voltage response time to either ceiling not more than 50ms
for a 2-5% step change from rated voltage under open-circuit
conditions and;
• A linear response between ceilings
• Positive and negative ceilings not less than 200% and 140% of
rated field voltage at rated terminal voltage and rated field
current
• A positive ceiling not less than 150% of rated field voltage at
rated terminal voltage.
Software Tools for Field Testing
to IEEE 421.2 Performance Expectations:
2-5% Voltage Step Change in AVR Mode
OverExcitation
Limiter Testing
Under Excitation Limit
Dynamic Step Test
11
Frequency
Response
Measurement
for PSS
compensation
*figure courtesy KPE
Built-in Dynamic System Analyzer to perform
Generator Frequency Response with Bode Plot
Chart Recorder to monitor the
Generator Output
Internal Dynamic System Analyzer
via software
Bode Plot to display immediate
system results
Questions
1
Use of the new revisions of IEEE
Standards 421.2 and 421.5 to satisfy
international grid code requirements
Overview of Grid Codes
Presented by: Robert Thornton-Jones
Brush Electric - UK
[email protected]
2
Introduction
• In North America, we have the NERC Reliability
Standards in place. In other regions around the world,
local grid codes have similar requirements.
• The Excitation System SC will report on our many
recent activities related to testing and modeling of
excitation systems, associated controllers and limits to
support meeting these requirements
• See also our companion presentation 16PESGM2680
‘“The Impact of Grid Codes Upon Generator Excitation System
Design and Standards”
3
Presentations
Presentation
421.2 Guide for Identification, Testing and
Evaluation of Dynamic Performance
421.5 Recommended Practice for Models for
Power System Stability Studies
Overview of grid codes
Practical international experiences
421.5 sample data and model data usability
Testing model data usability
Power System Stabilizer tuning criteria
Excitation limiter models and protection
coordination
Presenter
Organization
Rich Schaeffer
Basler Electric
Les Hajagos
Kestrel Power
Robert ThorntonBrush Electric
Jones
José Taborda
JT Consulting
Quanta
Alex Schneider
Technology
Leo Lima
Kestrel Power
Bureau of
Shawn Patterson
Reclamation
Les Hajagos
Kestrel Power
UK GRID CODE :
COMPLIANCE PROCESS

UK Grid Code Applies to…


All Transmission Connected Power Stations
•
i.e. Connection Points >132kV
•
Most Generators > 200MW are Transmission Connected
Embedded Large Power Stations
•

According to Registered Capacity – see below
Medium power stations where CUSC Contract is with National Grid not DNO
(CUSC = Connection and Use of System Code contract)

UK Grid Code Does Not Apply to Small Power Stations

Classifications of Power Stations by Registered Capacity (RC)

England & Wales (NGET Area)
Large ≥ 100MW, Medium ≥ 50MW, Small < 50MW

South of Scotland (SPT Area)
Large ≥ 30MW, Small < 30MW

North of Scotland (SHETL Area)
Large ≥ 10MW, Small < 10MW
UK GRID CODE :
COMPLIANCE PROCESS

Most National Grid compliant generators are >= 250MW

Existing Grid Code may change with ENTSOE arriving – see later
•

Existing Grid Code invoked if the Power Station is > 100MW
•

likely to revert to Generator Rating rather than Power Station Rating
hence for a 105MW generator on site with 6MW of auxiliaries Grid Code would not
apply
Guidance Notes for Synchronous Generators
•
Full Grid Code is nearly 600 pages written by lawyers !!
•
Guidance Notes explain procedures to follow and Grid Code requirements for
generators in a more readable form.
http://www.nationalgrid.com/NR/rdonlyres/B4DF2400-96FD-40E5-AF448DB88AADA5DF/56510/GuidanceNotesforSynchronousGeneratorsIssue12September2
012.pdf
UK GRID CODE :
TECHNICAL REQUIREMENTS

Technical Requirements

Short Circuit Ratio >= 0.5


This requirement has been relaxed for new large nuclear sets but not for
medium & smaller
Transient Voltage Control...
Stepping from 90% to 100% Ut in 600ms, damped to within 5% in < 3s.

BCA Specifies Time to Achieve Uf …
Can be 50ms to 300ms

BCA Specifies Excitation On Load Positive Ceiling for 10% Ut Drop…
Can be up to 4pu, typically 2pu to 3pu

Power System Stabilizer Required
To be demonstrated with random noise injection (200mHz to 3Hz)
http://www.nationalgrid.com/NR/rdonlyres/67374C36-1635-42E8-A2B8B7B8B9AF2408/57423/0_FULL_GRID_CODE_I5R1.pdf
UK Grid Code\GBGridCodeI3R27-appendix6-AVR.pdf
UK Grid Code\pp_09_32ShortCircuitRatio.pdf
UK Grid Code\relaxation of SCR letter.pdf
EUROPEAN GRID CODE :
TECHNICAL REQUIREMENTS

5 European Synchronous Power System Areas.

Categorization into Type requirements A, B, C or D, for
generating units according to size and connection point
location.

as with Hydro Quebec and BC Hydro….
certain Voltage Ranges proposed to exceed those of the IEEE C50.13
and IEC 60034 standards
e.g. Type D generators in the Baltic area, continuous operation at
1.10pu voltage is proposed as a requirement

ENTSO-E is likely to revert to Generator Rating rather than the
Present UK Power Station Rating
RUSSIAN GOST STANDARDS
GOST & NIIPT / SO-UPS-OJSC
 Excitation Systems for Turbogenerators (GOST 21558-2000)
 Requirements mandatory >60MW
 4.7 Voltage excitation forcing ratio and current excitation forcing >= 2.
•
4.10 Operating speed of excitation during forcing < 60ms for high speed systems
Total de-forcing time < 150ms.
•
4.12 Delay of system under forcing:
•
< 30ms for low speed systems
•
< 20ms for high speed system
 Generally aiming for static excitation system
AUSTRALIAN NATIONAL ELECTRICITY RULES :
COMPLIANCE PROCESS

NER has 3 Access Standards : Usually aim for highest “Automatic”

“R1” Data Collection – Factory Test & Design Data

“R2” Data Derived from On-System Testing

See 2008 AEMO “Generating System Model Guidelines”
AustrailianGridCode\Generating System Model Guidelines.pdf

Require specified format model configuration files

R1 Requires Significant Extra Resources and Time for…

Test of brushless generator with Test Slip Rings

Combined Generator & Excitation Test

Full Test of Limiters

Full Testing of Switch to Standby

Verification of Power System Stabilizer Test
AUSTRALIAN NATIONAL ELECTRICITY RULES :
TECHNICAL REQUIREMENTS

Regulation of voltage to within 0.5% of the set point.

Voltage set point to be continuously controllable in the range of at
least 95% to 105%.

Excitation ceiling voltage must be 1.5 times that required for rated
operation. (2.3 times for static systems.)

Settling times for a step change of voltage set point must be…

less than 2.5 seconds for a 5% voltage step on open circuit.

less than 5.0 seconds for a 5% voltage step with the generating unit
on load (active and reactive) with AVR limiters not operating

less than 7.5 seconds for a 5% voltage step with the generating unit
on load (active and reactive) when operating into an AVR limiter from
an operating point where a voltage step of 2.5% would just cause the
limiter to operate. This applies to each limiter.

Ability to increase field voltage from rated to ceiling in less than
500ms. (50ms for static systems.)

Power System Stabilizer including the usual features such as
output limiter, data recording and test facilities.
IRISH GRID CODE :
TECHNICAL REQUIREMENTS

Wind Turbines to Provide the island with >37% of Demand by 2020

Average On-Line Synchronous Inertia to be Reduced by 25%

Hence Much Greater Emphasis on Validation Testing



Site-work needs to be planned carefully
Leading Var Capability of 0.7 Power Factor at 35% Registered Power Capacity.

More Onerous Than Other Grid Codes.

Need to be Prepared to Demonstrate.
Possible Future Requirement for Higher Inertia Machines to Compensate for
Wind Penetration.
1
2016 IEEE/PES General Meeting
July 17th-21st, 2016 – Boston, MA
Panel Session
Use of the New Revisions of IEEE Std. 421.2 and 421.5 to
Satisfy International Grid Code Requirements
Testing model data usability
Excitation Systems
PSS
Limiters
Presented by: Leo Lima
Kestrel Power Engineering – USA
[email protected]
2
Introduction
• North American reliability standards
• NERC Std. MOD-026 and MOD-027
–Transmission Planner has 90 calendar days to respond if
provided models are usable or not.
• Models initialize without error
• No spurious behavior during a no-disturbance (flat) simulation
• Adequate response (stable response) following a disturbance that is
otherwise stable
• Usability in these Standards is not related to an
assessment of adequacy of the dynamic response of
the equipment
3
Full System Model
• Update models to the database of the full
interconnected system model
• NERC Model Validation Procedures
– Routine Tests
• No-fault test (no-disturbance test)
• Ring down test
• Regional tests
• NERC Std. MOD-032
• NERC Std. MOD-033
4
Simplified Tests
•
•
•
•
•
•
Open Circuit Step Response
Response Ratio Test
Online Voltage Reference Step Response
PSS model testing
Excitation limiter testing
Turbine/speed governor testing
5
Open Circuit Step Response
– Each generation unit is initially operating at full
speed, no load (not synchronized to the grid)
– Could be an automatic function of the software,
such as PSS/E ESTR/ERUN
– Results are comparable to actual equipment
commissioning tests
– Excellent for checking excitation system (AVR)
dynamic response
– Also checks some parameters of the synchronous
generator model
6
Open Circuit Step Response
– Does not test PSS models
– Might not be applicable to test excitation limiter
models
– Might not test the limits (ceilings) of the excitation
system
7
Response Ratio Test
– Response Ratio (aka Excitation System Nominal
Response) is defined in IEEE Std. 421.2
– Provides the value for the rated field voltage and
current of the equipment
– Might test the excitation system limits (positive
ceiling)
– Might not be applicable to high-initial response
excitation systems, particularly when field current
limiters (e.g. OEL) is not represented in the
simulation
8
Online Voltage Reference Step
– Single machine versus infinite bus (SMIB) model
– Comparable to actual field commissioning tests
– Related to the local mode of oscillation of the unit
– Oscillation frequency in the simulation is related
to the generator dispatch and the value of the
transfer impedance in the SMIB system
– Simulations with and without the PSS model will
show the PSS contribution to damping at this
oscillation frequency
9
Synthetic System
et
iG
E
Re
Xe
iline
Pload +j Qload
•
•
Load as constant impedance
F. P. Demello and C. Concordia, "Concepts of Synchronous Machine Stability as Affected by Excitation
Control," in IEEE Transactions on Power Apparatus and Systems, vol. PAS-88, no. 4, pp. 316-329, April
1969.
doi: 10.1109/TPAS.1969.292452
Load as constant power
F. J. De Marco, N. Martins and J. C. R. Ferraz, "An automatic method for power system stabilizers phase
compensation design," in IEEE Transactions on Power Systems, vol. 28, no. 2, pp. 997-1007, May 2013.
doi: 10.1109/TPWRS.2012.2209208
10
PSS Model Testing
• Using the synthetic system, effect of PSS on
oscillation damping can be assessed for any
frequency of interest
• For low frequencies (inter-area modes), most
of the generator output is feeding the local
load, not being transferred to the infinite bus
• Limited overall effectiveness of the PSS, as it is
modulating just a small fraction of the total
power output of the generator
11
PSS Model Testing
2900
2700
PSS
no PSS
2500
Et
(kV)
20.1
19.9
19.7
Efg
(Vdc)
19.5
speed
(pu)
• Local mode
SMIB
no local load
XE = 20%
P
(MW)
3100
200
150
100
50
0
-50
0.0010
0.0005
0
-0.0005
-0.0010
-0.0015
0
2
4
Time (seconds)
6
8
10
12
PSS Model Testing
2880
P
(MW)
2800
2760
PSS
no PSS
2720
20.2
Et
(kV)
20.0
19.8
19.6
Efg
(Vdc)
19.4
200
150
100
50
0
-50
0.00075
speed
(pu)
• Inter-area
SMIB
local load
XE = 200%
2840
0.00025
-0.00025
-0.00075
0
5
Time (seconds)
10
15
13
PSS Model Testing
3300
• No PSS
P
(MW)
3100
2900
2700
2500
XE=20 pu
XE=2.0 pu
XE=0.2 pu
2300
0.002
spd dev
(pu)
0.001
0
-0.001
-0.002
0
5
10
Time (seconds)
15
20
25
14
Excitation Limiter Testing
• How to check these models for usability?
– Commissioning field tests often performed at
modified settings (lowered limits)
– Disturbances resulting in activation of the limiters
are not common
• Suggestion
– Single machine versus “almost” infinite bus system
– Replace infinite bus by a conventional synchronous
generator with excitation system
15
Excitation Limiter Testing
• Suggested Test System
– Step in voltage reference, to simulate a change in
the grid voltage
– Positive step → high system voltage → machine goes
under excited until reaching UEL
– Negative step → low system voltage → machine
goes over excited until reaching OEL
– Relationship DQ/DET is inversely proportional to the
equivalent impedance XE
16
Turbine/Speed Governor Testing
• Isolated (islanded) operation or grid-connected
operation?
– Very important distinction, particularly for hydro units
– PSS/E activities GSTR/GRUN automate the test for isolated
system conditions
– No automated features to test grid-connected response
• Playback of recorded system frequency
disturbances
17
Turbine/Speed Governor Testing
• Suggested Test System
– Single machine versus “almost” infinite bus system
– Replace infinite bus by a conventional synchronous
generator with excitation system and speed
governor
– Add a local load at the “almost” infinite bus, to make
the equivalent machine a generator and to allow a
step change in total system load
– Adjust magnitude of the step in the system load and
parameters of the equivalent governor as necessary
18
Turbine/Speed Governor Testing
et
iG
E
Re
Xe
Pload +j Qload
60.2
60.15
60.1
60.05
frequency (Hz)
60
59.95
WECC trace
59.9
PSS/E Simulation
59.85
59.8
59.75
59.7
59.65
0
10
20
30
time (seconds)
40
50
60
1
Use of the new revisions of IEEE
Standards 421.2 and 421.5 to
satisfy international grid code
requirements
Power System Stabilizer Tuning Criteria
Shawn Patterson
Bureau of Reclamation – USA
[email protected]
2
Power System Stabilizers
(PSS)
• Required in some areas for decades (WECC,
Ontario/Quebec-NPCC)
• NERC Regional Standard – Western Electricity
Coordinating Council (WECC)
• Dual input is normal standard requirement
(WECC, Brazil, Most Canadian Provinces)
3
PSS
• Application of PSS appears as an element in
the 421 series of IEEE standards:
• 421.5 includes standard models of PSS
equipment used by manufacturers
• 421.2 includes information on dynamic
performance testing of excitation systems that
incorporate PSS
4
Power System Stabilizer Models
IEEE Standard 421.5
PSS2C is the latest version of the dual input stabilizer
VSI1max
VSI1
VSTmax
sTW1
sTW2
1
1+sTW1
1+sTW2
1+sT6
+
S
+
VSI1min
sTW3
u1
1+sTW3
sTW4
1
VSI2min
(1+sT9)M
N
+
S
–
KS1
1+sT1
1+sT3
1+sT10
1+sT12
1+sT2
1+sT4
1+sT11
1+sT13
VPSS
VSTmin
KS3
VSI2max
VSI2
1+sT8
1+sTW4
u2
block
bypass
logic
(a)
y
KS2
1+sT7
PSS
VST
output
logic
(b)
5
Power System Stabilizer Models
IEEE Standard 421.5
PSS4C is the latest version of the multi-band variant
VVLmax
KVL1
KVL2
DwL-I
KL1
KL2
KI1
KI2
DwH
KH1
KH2
KVL11+sTVL1
1+sTVL3
1+sTVL5
1+sTVL2
1+sTVL4
1+sTVL6
KVL17+sTVL7
1+sTVL9
1+sTVL11
1+sTVL8
1+sTVL10
1+sTVL12
KL11+sTL1
1+sTL3
1+sTL5
1+sTL2
1+sTL4
1+sTL6
KL17+sTL7
1+sTL9
1+sTL11
1+sTL8
1+sTL10
1+sTL12
KI11+sTI1
1+sTI3
1+sTI5
1+sTI2
1+sTI4
1+sTI6
KI17+sTI7
1+sTI9
1+sTI11
1+sTI8
1+sTI10
1+sTI12
KH11+sTH1
1+sTH3
1+sTH5
1+sTH2
1+sTH4
1+sTH6
KH17+sTH7
1+sTH9
1+sTH11
1+sTH8
1+sTH10
1+sTH12
+
S
KVL
VVL
–
VVLmin
VLmax
+
S
KL
VL
–
S
VLmin
VImax
+
S
KI
VI
–
VImin
S
S
VST
VSTmin
VHmax
+
VSTmax
KH
VH
–
VHmin
6
IEEE Standard 421.2
• Details both large and small signal
performance analysis, requirements, and
characteristics of excitation systems
– PSS performance rests upon performance of the
automatic voltage regulator (AVR)
• References the IEEE tutorial document for a
comprehensive treatment of PSS theory,
application, testing, and performance
7
IEEE PSS Tutorial
• Originally developed and published in 1981
• Updated version first presented by the
Excitation Systems Subcommittee in 2007
IEEE Tutorial Course in Power System Stabilization via Excitation Control,
Excitation Systems Subcommittee, Energy Development and Power Generation
Committee, Power & Energy Society, publication 09TP250, first presented at the
2007 IEEE PES General Meeting, Tampa, FL
(http://resourcecenter.ieee-pes.org/pes/product/tutorials/PES09TP250)
8
421.2
• Basic requirements for tuning AVRs, with and
without PSS
– Small signal, time domain performance indices
(step response rise time, overshoot, regulation,
damping ratio)
• Performance measurements required to
determine PSS effectiveness
– Frequency domain methods and measurements
9
421.2
AVR response
Transient Stability
vs.
Small Signal Stability
10
421.2
Testing Basics
11
421.2 (PSS Tutorial)
Tuning and Performance
Tuning requirement
Note: This also doubles as MOD-026 compliance documentation
12
PSS Elements
Signal conditioning
And mixing
Gain
Compensation
Limiter
VSI1max
VSI1
VSTmax
sTW1
sTW2
1
1+sTW1
1+sTW2
1+sT6
+
S
+
VSI1min
sTW3
u1
sTW4
1
+
S
–
KS1
1+sT1
1+sT3
1+sT10
1+sT12
1+sT2
1+sT4
1+sT11
1+sT13
VPSS
PSS
VST
output
logic
(b)
VSTmin
1+sTW3
VSI2min
(1+sT9)M
N
KS3
VSI2max
VSI2
1+sT8
1+sTW4
u2
block
bypass
logic
(a)
y
KS2
1+sT7
All elements covered comprehensively in the IEEE PSS tutorial
13
PSS Requirements*
(*as specified in some regions)
Compensation (e.g.,
within 30 degrees)
Washout (maximum time)
VSI1max
VSI1
VSTmax
sTW1
sTW2
1
1+sTW1
1+sTW2
1+sT6
+
S
+
VSI1min
sTW3
u1
sTW4
1
+
S
–
KS1
1+sT1
1+sT3
1+sT10
1+sT12
1+sT2
1+sT4
1+sT11
1+sT13
VPSS
PSS
VST
output
logic
(b)
VSTmin
1+sTW3
VSI2min
(1+sT9)M
N
KS3
VSI2max
VSI2
1+sT8
1+sTW4
u2
block
bypass
logic
(a)
y
KS2
1+sT7
Gain
Limiter (minimum
(minimum requirement) requirement, e.g.,
5 percent)
14
Adequate?
• AVR and PSS application are some of the most
difficult topics for reliability organizations, grid
codes, compliance offices
• The combination of the 421 standard series
(including the referenced PSS tutorial)
provides more than enough information for
the purposes of reliability standards
15
More
• If anything, these documents should be
referenced and consulted more
– Voltage regulation requirements are usually very
simplistic
– PSS requirements are lesser known, but are
tending to become more technical
– Grid codes are just starting to get a handle on
performance requirements/standards, so these
documents will be essential
1
Excitation Limiter Models and
Protection Coordination
Presented by: Les Hajagos
Kestrel Power Engineering – Canada
[email protected]
2
Introduction
• In North America, we have the NERC Reliability
Standards in place. In other regions around the world,
local grid codes have similar requirements.
• The Excitation System SC will report on our many
recent activities related to testing and modeling of
excitation systems, associated controllers and limits to
support meeting these requirements
• See also our companion presentation 16PESGM2680
‘“The Impact of Grid Codes Upon Generator Excitation System
Design and Standards”
3
Presentations
Presentation
421.2 Guide for Identification, Testing and
Evaluation of Dynamic Performance
421.5 Recommended Practice for Models for
Power System Stability Studies
Overview of grid codes
Practical international experiences
421.5 sample data and model data usability
Testing model data usability
Power System Stabilizer tuning criteria
Excitation limiter models and protection
coordination
Presenter
Organization
Rich Schaeffer
Basler Electric
Les Hajagos
Kestrel Power
Robert ThorntonBrush Electric
Jones
José Taborda
JT Consulting
Quanta
Alex Schneider
Technology
Leo Lima
Kestrel Power
Bureau of
Shawn Patterson
Reclamation
Les Hajagos
Kestrel Power
4
Excitation Limiters and Protection:
Excitation limiters must coordinate with equipment
capabilities (generator, exciter, transformers…) and with
internal and external protections and ride-through
requirements
Excitation, power equipment and relaying are typically
different departments in a utility – must coordinate
and communicate!
5
IEEE 421 Series of Standards
• 421.1 Standard Definitions
• 421.2 Guide for Identification, Testing and Evaluation
of Dynamic Performance
• 421.3 High-Potential Test Requirements
• 421.4 Guide for Preparation of Specifications
• 421.5 Recommended Practice for Models for Power
System Stability Studies
• 421.6 Specification and Design of Field Discharge
Equipment
6
NERC Standards (Excitation Related)
• PRC-005-2 Protection System Maintenance – may impact new
exciters with built in protection
• PRC-019-2 Coordination of Generating Unit or Plant
Capabilities, Voltage Regulating Controls, and Protection
• PRC-024-1 Generator Performance During Frequency and
Voltage Excursions
7
NERC PRC-019-2 Verification that generator voltage regulator controls and limit
functions are coordinated with the generator’s capabilities and protective relays
Study results with plots or data that could be plotted for the following:
•
Generator capability curve, including specification of nominal voltage, ambient air or
cooling temperature, or hydrogen pressure.
•
Steady state over-excitation limiter and under-excitation limiter characteristics
•
MW limit of the prime mover.
•
Any other limit that could restrict the megawatt or megavar capability.
•
Loss of excitation / field protective relay characteristics.
•
Volts-per-hertz protection vs volts-per-hertz limiters
•
Time vs. field current or time vs. stator current
8
NERC PRC-019-2 Verification that generator voltage regulator controls and limit
functions are coordinated with the generator’s capabilities and protective relays
1.1. Assuming the normal automatic voltage regulator control
loop and steady-state system operating conditions, verify the
following coordination items for each applicable Facility:
1.1.1. The in-service limiters are set to operate before the Protection
System of the applicable Facility in order to avoid disconnecting the
generator unnecessarily.
1.1.2. The applicable in-service Protection System devices are set to
operate to isolate or de-energize equipment in order to limit the
extent of damage when operating conditions exceed equipment
capabilities or stability limits.
9
Excitation Limiters
•
•
•
•
Over-Excitation Limiters (OEL)
Under-Excitation Limiters (UEL)
Over-Voltage (O/V) and V/Hz
Stator Current Limiter (SCL)
10
Reactive Capability Coordination
50
Example:
NERC PRC-019 Coordination
OEL
Rated Field
SCL
Stator Limit
UEL
PQ Monitor Trip
Minimum Field
40 Zone 2
40 Zone 1
Rated PF 0.9
0.95 PF
40
30
20
Reactive Power (MVAr)
Grid Codes may impose
coordination of limiters,
protection and capability and
may also impose minimum
reactive capability
requirements.
10
0
-10
-20
Some types of limiters may be
prohibited or may be
mandatory (e.g. SCL)
-30
-40
*example plot courtesy Kestrel Power Engineering.
-50
Active Power (MW)
0
10
20
30
40
50
11
HV Grid
Unit
Breaker
Main
Transformer
24T
Overview of
Protective
Devices
PT
Relays
40
Controls
Limiters
CT
21
59
32
24
Service Transformer
Exciter
~
M
Generator
51V
50
5IE
M
Auxiliary
Loads
M
12
Field Thermal Coordination
Example: Provide shorttime capabilities
specified in IEEE/ANSI
50.13 and continuous
capability determined by
either field current,
armature current, or
core-end heating. More
restrictive limiting
functions, such as steady
state stability limiters,
shall not be enabled
without ISO approval.
*example plot courtesy Kestrel Power
Engineering.
13
V/Hz Coordination Example
Coordination may include the excitation limiter, relays, the generator and other
equipment, here the GST. Often equipment damage curves are not available
and we instead refer to applicable protection standards *example plot courtesy KPE
14
Example UEL Curve For A Cylindrical Rotor Generator
Reactive Power (pu)
0
LOE
directional
-0.2
UEL
LOE
-0.4
-0.6
0
0.2
0.4
0.6
0.8
Active Power (pu)
1.0
1.2
15
Example UEL Dynamic Response
-0.2
Reactive Power (pu)
UEL
LOE
-0.4
-0.6
-0.8
NO UEL
0
2
4
6
Time (seconds)
8
10
16
Example UEL Dynamic Response
Generator Apparent Impedance X (pu)
0
-0.2
0 (start)
0.42
LOE
directional
-0.4
1.67
3.05
impedance
-0.6
UEL
LOE
-0.8
-1.0
0.5
0.7
0.9
1.1
1.3
Generator Apparent Impedance R (pu)
1.5