SYNCHROPHASOR SOLUTIONS FOR THE SMART GRID
October 5, 2011
Ken Martin Electric Power Group
Real Time Dynamics
Monitoring System Alarming
Phasor Grid Dynamics Analyzer
enhanced PDC
Presenta:on
• Introduction to synchrophasors • Synchrophasor characteristics • Synchrophasor applications • Synchrophasor systems
Tradi:onal power system measurements
• Voltage • MW, MVAR • RMS magnitude • Average
reading over 100 ms +
• Report 1-2 sec • Timetag at EMS
Voltage
Data output
RMS magnitude
MW MVAR
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0
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Phasor measurements
• Voltage • Current • Frequency • Magnitude & phase
angle • 1-5 cycle averaging • Report 10-60/sec • Timetag at
measurement • Can compute MW,
MVAR
Data output
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0
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. f A
PMU
Phasor Representa:on
.
A phasor is the complex form of the AC waveform
√2 A cos (2 p ω0 t + f) A ejf
-1
-0.5
0
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1
-50 0 50 100 150 200 250 300 350 400
f f A
A
Basic phasor calcula:on • Discrete Fourier Transform
(DFT) • Fourier coefficients from cos &
sin waves (kø) • Multiply & sum with waveform
samples (xk) • Time & frequency reference
arbitrary
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φkxN
X kr cos2∑=
ir jXX −=X
φkxN
X ki sin2∑=
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Synchrophasor calcula:on • Reference sine/cosine reference to nominal frequency (ω0) • Time reference fixed - UTC time • Estimation windows move in time, sinusoid reference fixed • Measurements can be made in 1 cycle
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WINDOW 1 WINDOW 2 WINDOW 3
Reference: Cosine – black Sine - red
Waveform being sampled
Time & reference angle
.
Phase angle is computed relative to UTC time reference • Time is common reference for all angles • ANY phasor can be used for reference • A time error results in an angle error
• Time errors are detected & flagged
-1
-0.5
0
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1
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f A
√2 A Actual time T = 0 Actual phasor
value
Reported phasor value
Off nominal frequency
• f > f0, CCW rotation; f < f0, CW rotation
f2
f1
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f2 f1
f2
f1
f > f0
f < f0
f = f0 f1 f2
-‐-‐ a typical Phasor Measurement Unit
DFT
DFT
DFT Time synchronized sampling of three phase waveform. 12 samples/cycle (720/sec). Discrete Fourier Transform uses 12 samples for each phasor conversion.
60 Hz component
Symmetrical Component Transformation
Frequency & Rate-of- Change of Frequency Algorithm
Disturbance and transient detectors, data table storage
Phasors
Trigger flags
Frequency, dFreq/dt
Real Time Data Output
GPS Timing
Phasor Measurement Process
Phasors provide accurate frequency
• Frequency is rate of change of Phase • F = D(q-f) / (t2 - t1) • Accuracy better than .005 Hz • Measurement in < 1.5 cycles
Vt1
q f
Vt2
Phasors provide MW, MVAR
• Power P = V I cos(q-f) = VI = Vx Ix + Vy Iy • Reactive Power Q = V I sin(q-f) = V (jI)
= Vy Ix - Vx Iy
V e = Vx + j Vy
I e = Ix + j Iy
jq
jf q
f
Phasors indicate safe power flow
• Power flow follows voltage phase angle – Power flow: P = V1 V2 sin(θ - ø)/Z
• Synchrophasors measure phase angle with universal time – Allows comparison over wide area
• Across lines for traditional 2 machine stability
• Across regions to monitor bulk power flow
V1 e V2 e jq jf
Line impedance Z
P
Substation 1 Substation 2
0 45 90 135 1800
1
0 90 180
P Unsafe
Safe
Applica:ons – data analysis
• Off-line analysis • Use recorded data
– Verification of operations – Analyze dynamic
performance – System model maintenance
© Electric Power Group 14
Model Valida:on: Ringdown analysis of real data
The modal estimates (dotted line) are a good fit to the real data , indicating that
the ringdown analysis results are accurate
Dominant mode at .29 Hz---close to the simulated mode
© Electric Power Group
Inter-‐area System Swing • Frequency:
F = d/dt • Clearly shows system
acceleration • Shows reaction
progressing through system: – Yellow nearest event – Purple furthest away – Green near middle
• High-speed, precise timetag allows these measurements
System monitoring & visualiza:on
• Wide-area displays – Actual measurement in real-time
(strip-chart) – System setup & operation
• Operation use – Operational awareness – Confirmation of dynamic operation
(SCADA too slow) – Overall system – Detail reporting
© Electric Power Group
Wide Area Situa:onal Awareness -‐ EI
November 9, 2010
Wide Area Situa:onal Awareness – WECC
System monitor & alarms
• Integration of all data sources – Phasors for dynamic operation – EMS for static reporting
• Operational systems & alarms – Limit alarms
• Line loading • Phase angle, cut plane
– State estimation
• Particularly from phasors – Low damping – Islanded sections – Event location
Ve-jf Ve-jf
Ve-jf Ve-jf
Page 20
Spectral Monitoring of Select Signal
Mode Estimates
Most Significant Mode
Small Signal Monitoring
© Electric Power Group
Other monitor metrics …detect Grid Stress (angle separa:on).
…detect Dangerous Oscilla:ons – reveal low damping.
…detect Frequency Instability / Islanding.
…detect Generator or Line Trip condi:ons.
…detect Low Voltage (Instability) condi:ons.
…determine System Norm or Baseline.
…perform Event Analysis .
Grid stress -- Angle separation
Small Signal instability -- % damping
Frequency Instability -- cohesive-ness
Dangerous inter-area Oscillations – dynamic stress
System control applica:ons
• System protection & control – Wide area problem detection – Low and high speed operation
• Applications include – Out-of-step detection & remediation – Excessive power flow relief – Reconfiguration for high phase
angles – System oscillation damping – Controller modulation & supervision – Relay adaptive control & supervision
PMU PDC (Data Concentrator)
~ SVC
)( Controller
PMU
PMU
Signal Delay -‐ PMU to PDC
• Direct connection through local hub • Ave delay 4.4 ms, max 5.4 ms
• Remote installation, 200 mi distance • 2 routers, synchronous WAN, 128 KBPS • Ave delay 17.5 ms, max 18.7 ms
• Communication with Ethernet connections • 10M BPS system
0 500 1000 1500 2000 2500 3000 3500 40004.2
4.4
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5.8Delay - ABB PMU
Milli
seco
nds
Data Points0 200 400 600 800 1000 1200 1400 1600
16.8
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18.8Delay - McNary 500 PMU, samples
Milll
isec
onds
Data Points
Comparison of Frequency & Phase Angle -‐ Power Flow
Grand Coulee frequency - blue, Coulee - Vincent phase angle - red, San Onofre power - green
~0.4 sec
Power Compensation (southern Cal)
Initial fault
GC frequency N. Washington
• Event occurred in N. Washington where frequency recorded
• Reaction recorded in Los Angeles area
• Power system event reaction travels slower than phasor measurement and communication
• An event can be measured, the severity estimated, and appropriate control action in another area can be taken before adverse action occurs
WECC Wide Area Control
• Tie lines from the Pacific NW to California (red)
• Loss of generation in California – Tie lines overload – N-S systems go out of
step – Systems separate – Large load loss
• Control strategy – Phasors detect swing,
data sent to controller in NW (green) - (0.2 s)
– Drop generation to prevent tie line overload (0.5 s)
– Action complete before overload occurs (1.0 s)
P H O E N I X A R E A
M I G U E L N . G I L A
V A I L P A L O V E R D E
C H O L L A G L E N
C A N Y O N N A V A J O S P R I N G - E R V I L L E
F O U R C O R N E R S
G R E E N L E E W E S T M E S A
S A N J U A N B L A C K W A T E R C O R O N A D O
A R T E S I A A M R A D
C A L I E N T E D I A B L O
D E N V E R A R E A C R A I G
R I F L E B O N A N Z A B E N L O M O N D
C A M P W I L L I A M S
M I D P O I N T V A L M Y
T R A C Y H A R R Y A L L E N
M A R K E T P L A C E I N T E R - M O U N T A I N
S I G U R D H U N T E R / E M E R Y
P I N T O R E D B U T T E D E V E R S L O S
A N G E L E S A R E A
M E D F O R D M A L I N
R O U N D M T . O L I N D A
T A B L E M T . V A C A - D I X O N
T E S L A S A N L U I S
G A T E S D I A B L O C A N Y O N M I D W A Y
S U M M E R L A K E G R I Z Z L Y B R O A D M A N P O R T L A N D
A R E A H A R T F O R D M I D W A Y
C H I E F J O E S P H
G R A N D C O U L E E N A N E U M
L O W E R M O N U M E N T A L
D W O R S H A K T A F T G A R R I S O N T O W N S E N D
B R O A D V I E W C O L S T R I P
J I M B R I D G E R L A R M I E
R I V E R S T A . B O R A H B R A D Y
S E A T T L E / T A C O M A A R E A
S A N F R A N C I S C O A R E A
© Electric Power Group
Large genera:on loss example • 2750 MW Generation loss
in SW near Phoenix • Intertie operating 2/3
capacity • Frequency drop near
generators immediate and large (plot b)
• Power ramp (plot a) and phase angle ramp (plot c) immediate & steady
• Voltage dip actually delayed start but drops fast
• Frequency may be better indicator
• Model controller detected swing correctly
• (Actual swing was barely stable)
Overall event – voltages over 20 sec
Event detail – 2 sec, voltages in plot d
© Electric Power Group
PMU’s w GPS
(Phasor Data Concentrator)
Real Time Monitoring & Alarming Platform
(Offline Analysis Software System)
3rd Party Historian
Basic Synchrophasor Network Architecture
Current Grid-‐wide/ISO system • Hierarchal architecture • Transmission Owner (TO)
– Installs PMUs & communication – Has PDC & applications for own PMUs – Stores data locally
• ISO/RTO – Coordinates installation & data flow – Collects data for grid-wide
measurement
• Issues include – Data identification – Data sharing & ownership – Maintenance & problem notification – Transmission delays
Application
TO PDC
PMU
TO PDC
TO PDC
PMU
PMU
PMU
PMU
PMU
PMU
PMU
PMU
Application
ISO PDC
Application
Application
Application
Application
N. America WISP ERCOT MISO NEISO NYISO PJM TVA Southern Co
World Wide China Japan India Russia Slovenia Denmark Germany France Spain S. Africa Brazil Mexico
Synchrophasor projects
© Electric Power Group 30
30
Standards IEEE C37.118.1 & C37.118.2
• IEEE C37.118.1 covers the measurement – Phasor and frequency – Steady-state and dynamic conditions – Includes measurement tests and limits
• IEEE C37.118.2 covers communications – Describes a simple messaging – Includes message contents and formats – Communication methods & protocols open – RS232 serial and IP TCP & UDP usually used
• Final approval expected in December 2011 • Publication expected in January 2012
© Electric Power Group 31
31
Standard IEC 61850-‐90-‐5
• Work started in October 2009 • Includes several additions to 61850
– New modeling – USV for routable sampled values – End-to-end security features
• Completed document to IEC in October 2011 • Final approval expected late 2011
© Electric Power Group
Future needs
§ Full grid visualiza-on
§ Wide area controls
§ Alarms for less predictable situa-ons – System & equipment oscilla-ons – Excessive system phase angles
§ Integra-on of renewables – Less predictable – Reduced iner-a
§ Many others!!!
08.17.10
201 South Lake Avenue, Ste 400 Pasadena, CA 91101 626-‐685-‐2015 www.ElectricPowerGroup.com
Real Time Dynamics
Monitoring System Alarming
Phasor Grid Dynamics Analyzer
enhanced PDC for Control Centers/
Substations
Ken Martin
Thank You -‐ Ques:ons?