SYNCHROPHASORS OLUTIONS FOR THE** SMARTG RID · • Voltage • MW, MVAR • RMS magnitude •...
Transcript of SYNCHROPHASORS OLUTIONS FOR THE** SMARTG RID · • Voltage • MW, MVAR • RMS magnitude •...
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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
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Presenta:on
• Introduction to synchrophasors • Synchrophasor characteristics • Synchrophasor applications • Synchrophasor systems
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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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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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. f A
PMU
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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
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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
-5 0 5 10 15 20 25 30 35-1
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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
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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
-50 0 50 100 150 200 250 300 350 400
f A
√2 A Actual time T = 0 Actual phasor
value
Reported phasor value
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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
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-‐-‐ 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
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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
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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
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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
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Applica:ons – data analysis
• Off-line analysis • Use recorded data
– Verification of operations – Analyze dynamic
performance – System model maintenance
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© 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
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© 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
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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
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© Electric Power Group
Wide Area Situa:onal Awareness -‐ EI
November 9, 2010
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Wide Area Situa:onal Awareness – WECC
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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
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Spectral Monitoring of Select Signal
Mode Estimates
Most Significant Mode
Small Signal Monitoring
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© 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
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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
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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
4.6
4.8
5
5.2
5.4
5.6
5.8Delay - ABB PMU
Milli
seco
nds
Data Points0 200 400 600 800 1000 1200 1400 1600
16.8
17
17.2
17.4
17.6
17.8
18
18.2
18.4
18.6
18.8Delay - McNary 500 PMU, samples
Milll
isec
onds
Data Points
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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
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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
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© 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
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© 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
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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
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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
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© 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
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© 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
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© 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
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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?