ece 476 power system analysis lecture 25: transient stability, geomagnetic disturbances prof. tom...
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ECE 476 Power System Analysis
Lecture 25: Transient Stability, Geomagnetic Disturbances
Prof. Tom Overbye
Dept. of Electrical and Computer Engineering
University of Illinois at Urbana-Champaign
Announcements
• Read Chapters 11 and 12 (sections 12.1 to 12.3)• Homework 11is 11.19, 11.25, 12.3, 12.11, 14.15; it
should be done before the final but is not to be turned in
• Design project due today• Final exam is Wednesday Dec 16, 7 to 10pm,
room 1013; comprehensive, closed book, closed notes with three note sheets and standard calculators allowed
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Generator Governors
• The other key generator control system is the governor, which changes the mechanical power into the generator to maintain a desired speed and hence frequency.
• Historically centrifugal “flyball” governors have been used to regulate the speed of devices such as steam engines
• The centrifugal force varieswith speed, opening orclosing the throttle valve
Photo source: en.wikipedia.org/wiki/Centrifugal_governor3
Isochronous Governors
• Ideally we would like the governor to maintain the frequency at a constant value of 60 Hz (in North America)
• This can be accomplished using an isochronous governor. • A flyball governor is not an isochronous governor since
the control action is proportional to the speed error• An isochronous governor requires an integration of the
speed error
• Isochronous governors are used on stand alone generators but cannot be used on interconnected generators because of “hunting”
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Generator “Hunting”
• Control system “hunting” is oscillation around an equilibrium point
• Trying to interconnect multiple isochronous generators will cause hunting because the frequency setpoints are the two generators are never exactly equal• One will be accumulating a frequency error trying to
speed up the system, whereas the other will be trying to slow it down
• The generators will NOT share the power load proportionally.
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Droop Control
• The solution is to use what is known as droop control, in which the desired set point frequency is dependent upon the generator’s output
1m refp p f
R
R is known as the regulation constantor droop; a typicalvalue is 4 or 5%.
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Governor Block Diagrams
• The block diagram for a simple stream unit, the TGOV1 model, is shown below. The T1 block models the governor delays, whereas the second block models the turbine response.
maxV
1
1
1 sT
minV
1
R
tD
2
3
1
1
sT
sT
refP mechP
ΔωSpeed
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Example 12.4 System Response
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Problem 12.11
slack
SLACK345
SLACK138
RAY345
RAY138
RAY69
FERNA69
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MVA
DEMAR69
BLT69
BLT138
BOB138
BOB69
WOLEN69
SHI MKO69
ROGER69
UI UC69
PETE69
HI SKY69
TI M69
TI M138
TI M345
PAI 69
GROSS69
HANNAH69
AMANDA69
HOMER69
LAUF69
MORO138
LAUF138
HALE69
PATTEN69
WEBER69
BUCKY138
SAVOY69
SAVOY138
J O138 J O345
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1.02 pu
1.01 pu
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1.00 pu1.00 pu
0.99 pu
1.02 pu
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1.00 pu
1.01 pu1.01 pu
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0.997 pu
0.99 pu
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1.00 pu1.01 pu
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1.00 pu 1.00 pu
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LYNN138
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1.00 pu
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218 MW 54 Mvar
21 MW 7 Mvar
45.3 MW 12 Mvar
140 MW 45 Mvar
37 MW
13 Mvar
12 MW 5 Mvar
150 MW -0 Mvar
56 MW
13 Mvar
15 MW 5 Mvar
14 MW
2 Mvar
42 MW 2 Mvar
45 MW 0 Mvar
58.2 MW 36 Mvar
36 MW 10 Mvar
0 MW 0 Mvar
22 MW 15 Mvar
60 MW 12 Mvar
20 MW 30 Mvar
23 MW 7 Mvar
33 MW 13 Mvar
16.0 Mvar 18 MW 5 Mvar
58 MW 40 Mvar 51 MW
15 Mvar
14.3 Mvar
33 MW 10 Mvar
15 MW 3 Mvar
23 MW 6 Mvar 14 MW
3 Mvar
4.8 Mvar
7.2 Mvar
12.8 Mvar
29.0 Mvar
7.4 Mvar
0.0 Mvar
106 MW 8 Mvar
20 MW 8 Mvar
150 MW -0 Mvar
17 MW 3 Mvar
0 MW 0 Mvar
14 MW 4 Mvar
20191817161514131211109876543210
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59.98
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59.9
59.88
59.86
59.84
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59.8
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59.74
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59.7
59.68
59.66
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Restoring Frequency to 60 Hz
• In an interconnected power system the governors to not automatically restore the frequency to 60 Hz
• Rather this is done via the ACE (area control area calculation). Previously we defined ACE as the difference between the actual real power exports from an area and the scheduled exports. But it has an additional termACE = Pactual - Psched – 10b(freqact - freqsched)
• b is the balancing authority frequency bias in MW/0.1 Hz with a negative sign. It is about 0.8% of peak load/generation
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2600 MW Loss Frequency Recovery
Frequency recovers in about ten minutes
2007 CWLP Dallman Accident
• In 2007 there was an explosion at the CWLP 86 MW Dallman 1 generator. The explosion was eventually determined to be caused by a sticky valve that prevented the cutoff of steam into the turbine when the generator went off line. So the generator turbine continued to accelerate up to over 6000 rpm (3600 normal). – High speed caused parts of the generator to shoot out– Hydrogen escaped from the cooling system, and
eventually escaped causing the explosion– Repairs took about 18 months, costing more than $52
million12
Dallman After the Accident
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Outside of Dallman
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High-Impact, Low-Frequency Events
• In 2010 the North American Electric ReliabilityCorporation (NERC) identified some severe grid threads called High-Impact, Low-Frequency Events (HILFs); others call them blackswan events or black sky days– Large-scale, potentially long duration blackouts
• HILFs identified by NERC were 1. a coordinated cyber, physical or blended attacks,
2. pandemics,
3. geomagnetic disturbances (GMDs), and
4. high altitude electromagnetics pulses (HEMPs)
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Geomagnetic Disturbances (GMDs)
• GMDs are caused by corona mass ejections (CMEs) from the sun; a GMD caused the Quebec blackout in 1989
• They have the potential to severely disrupt the electric grid by causing quasi-dc geomagnetically induced currents (GICs) in the high voltage grid
• Until recently power engineers had few tools to help them assess the impact of GMDs
• GMD assessment tools are now moving into the realm of power system planning and operations engineers
• Wide industry interest in GMD assessment
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In the News: National Space Weather Action Plan
• On 10/28/15 the White House released the National Space Weather Action Plan– Quoting from the Introduction, “Given the importance of
reliable electric power and space-based assets, it is essential that the United States has the ability to protect, mitigate, respond to, and recover from the potentially devastating effects of space weather.”
• Plan structure includes – 1) Establish Benchmarks, 2) Enhance Response and Recovery
Capabilities, 3) Improve Protection and Mitigation Efforts, 4) Improve Assessment, Modeling, and Prediction of Impacts on Critical Infrastructure, 5) Improve Space-Weather Services, 6) Increase International Cooperation
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Analysis Requires Consideration of Several Time Frames
Image: Sauer, P.W., M. A. Pai, Power System Dynamics and Stability, Stripes Publishing, 2007
GMDs impact grid on time scale of many seconds to hours, quasi-steady state analyzed by power flow
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Quick Demo of How the Grid Can Fail in the Power Flow Time Frame
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GMD Overview
• Solar corona mass ejections (CMEs) can cause changes in the earth’s magnetic field (i.e., dB/dt). These changes in turn produce a non-uniform electric fields– Changes in the magnetic flux are usually expressed in
nT/minute; from a 60 Hz perspective they produce an almost dc electric field
– 1989 North America storm produced a change of 500 nT/minute, while a stronger storm, such as the ones in 1859 or 1921, could produce 5000 nT/minute variation
– Storm “footprint” can be continental in scale– Earth’s magnetic field is normally between 25,000 and 65,000
nT, with higher values near the poles
Image source: J. Kappenman, “A Perfect Storm of Planetary Proportions,” IEEE Spectrum, Feb 2012, page 29 20
Electric Fields and Geomagnetically Induced Currents (GICs)
• The induced electric field at the surface is dependent on deep earth (hundreds of km) conductivity– Electric fields are vectors (magnitude and angle); values
expressed in units of volts/mile (or volts/km);– A 2400 nT/minute storm could produce 5 to 10 volts/mile.
• The electric fields cause GICs to flow in the high voltage transmission grid
• The induced voltages that drive the GICs can be modeled as dc voltages in the transmission lines. – The magnitude of the dc voltage is determined by integrating
the electric field variation over the line length– Both magnitude and direction of electric field is important
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July 2012 GMD Near Miss
• In July 2014 NASA said in July of 2012 there was a solar CME that barely missed the earth– It would likely have
caused the largestGMD that we haveseen in the last 150years
• There is still lots of uncertainly about how large a storm is reasonable to consider in electric utility planning
Image Source: science.nasa.gov/science-news/science-at-nasa/2014/23jul_superstorm/ 22
Geomagnetically Induced Currents (GICs
• GMDs cause slowly varying electric fields• Along length of a high voltage transmission line,
electric fields can be modeled as a dc voltage source superimposed on the lines
• These voltage sources produce quasi-dc geomagnetically induced currents (GICs) that are superimposed on the ac (60 Hz) flows
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Transformer Impacts of GICs
• The superimposed dc GICscan push transformers into saturation part of the cycle
• This can cause large harmonics; in the positive sequence (e.g., power flow and transient stability) these harmonics can be represented by increased reactive power losses in the transformer
Images: Craig Stiegemeier and Ed Schweitzer, JASON Presentations, June 2011
Harmonics
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GMD Enhanced Power Analysis Software
• By integrating GIC calculations directly within power flow and transient stability engineers can see the impact of GICs on their systems, and consider mitigation options
• GIC calculations use many of the existing model parameters such as line resistance. Some non-standard values are also needed; either provided or estimated– Substation grounding resistance– transformer grounding configuration, transformer coil
resistance, whether auto-transformer, whether three-winding transformer,
– generator step-up transformer parameters25
Overview of GMD Assessments
Image Source: http://www.nerc.com/pa/Stand/WebinarLibrary/GMD_standards_update_june26_ec.pdf
The two key concerns from a big storm are 1) large-scaleblackout due to voltage collapse, 2) permanent transformer damage due to overheating
In is a quite interdisciplinary problem
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Four Bus Example
,3
150 volts93.75 amps or 31.25 amps/phase
1 0.1 0.1 0.2 0.2GIC PhaseI
The line and transformer resistance and current values are per phase so the total current is three times this value. Substation grounding values are total resistance. Brown arrows show GIC flow.
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Determining GMD Storm Scenarios
• The starting point for the GIC analysis is an assumed storm scenario; determines the line dc voltages
• Matching an actual storm can be complicated, and requires detailed knowledge of the associated geology
• GICs vary linearly with the assumed electric field magnitudes and reactive power impacts on the transformers is also mostly linear
• Working with space weather community to determine highest possible storms
• NERC proposed a non-uniform field magnitude model that FERC has partially accepted (FERC has been seeking industry comments in summer of 2015) 28
Power Flow Embedded GIC Calculations: The G Matrix
• With knowledge of the pertinent transmission system parameters and the GMD-induced line voltages, the dc bus voltages and flows are found by solving a linear equation
I = G V
– The G matrix is similar to the Ybus except 1) it is augmented to include substation neutrals, and 2) it is just resistive values (conductances)
– The current vector contains the Norton injections associated with the GMD-induced line voltages
• Factoring the sparse G matrix is fast!29
G Matrix Considerations
•Data needed at least for the study footprint & neighbors• Transmission line resistance values are readily
obtained from the power flow cases• DC resistance is quite close to ac values; temperature dependence (0.4%
per degree C) plays a role
• Estimates of transformer winding resistance can be obtained from the power flow cases– Usually whether they are auto-transformers can be
determined– Whether device is a three winding transformer can usually be
guessed (if not explicitly modeled)
• Substation grounding values needed30
Input Electric Field Considerations
• The current vector (I) depends upon the assumed electric field along each transmission line
• With a uniform electric field determination of the transmission line’s GMD-induced voltage is path independent– Just requires geographic knowledge of the transmission line’s
terminal substations
• With nonuniform fields an exact calculation would be path dependent, but just a assuming a straight line path is probably sufficient (given all the other uncertainties!)
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EPRI Small 20 Bus Benchmark System Example
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Assumed Geographic Location (Mostly East-West)
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GIC Flows with a 1V/km North-South, Uniform Electric Field
slack
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23
15
4
205
6
11
12
18
19
1
7
8
13 14
900 MW 95 Mvar
900 MW 95 Mvar
500 MW
17 Mvar 500 MW 17 Mvar
600 MW
121 Mvar
600 MW
121 Mvar
779 MW
100 Mvar
900 MW
400 Mvar
1200 MW
350 Mvar
1200 MW
500 Mvar
Substation 2
Substation 1
Substation 3
Substation 4
Substation 5
Substation 6
Substation 8 21
500 MW 200 Mvar
Total GIC Losses 528.9 Mvar
536.8 Mvar
204.3 Mvar
300 MW 150 Mvar
600 MW
200 Mvar
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GIC Flows with a 1V/km East-West, Uniform Electric Field
slack
17 16
23
15
4
205
6
11
12
18
19
1
7
8
13 14
900 MW 181 Mvar
900 MW 181 Mvar
500 MW
31 Mvar 500 MW 31 Mvar
600 MW
131 Mvar
600 MW
131 Mvar
779 MW
118 Mvar
900 MW
400 Mvar
1200 MW
350 Mvar
1200 MW
500 Mvar
Substation 2
Substation 1
Substation 3
Substation 4
Substation 5
Substation 6
Substation 8 21
500 MW 200 Mvar
Total GIC Losses 758.3 Mvar
532.8 Mvar
205.0 Mvar
300 MW 150 Mvar
600 MW
200 Mvar
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GIC Flows with a 2V/km East-West, Uniform Electric Field
slack
17 16
23
15
4
205
6
11
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18
19
1
7
8
13 14
900 MW 400 Mvar
900 MW 400 Mvar
500 MW
113 Mvar 500 MW 113 Mvar
600 MW
300 Mvar
600 MW
300 Mvar
786 MW
198 Mvar
900 MW
400 Mvar
1200 MW
350 Mvar
1200 MW
500 Mvar
Substation 2
Substation 1
Substation 3
Substation 4
Substation 5
Substation 6
Substation 8 21
500 MW 200 Mvar
Total GIC Losses 1474.9 Mvar
493.2 Mvar
189.4 Mvar
300 MW 150 Mvar
600 MW
200 Mvar
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GIC Flows with a 2.2V/km East-West, Uniform Electric Field – Near Voltage Collapse
slack
17 16
23
15
4
205
6
11
12
18
19
1
7
8
13 14
900 MW 400 Mvar
900 MW 400 Mvar
500 MW
172 Mvar 500 MW 172 Mvar
600 MW
389 Mvar
600 MW
389 Mvar
792 MW
251 Mvar
900 MW
400 Mvar
1200 MW
350 Mvar
1200 MW
500 Mvar
Substation 2
Substation 1
Substation 3
Substation 4
Substation 5
Substation 6
Substation 8 21
500 MW 200 Mvar
Total GIC Losses 1587.5 Mvar
463.9 Mvar
179.3 Mvar
300 MW 150 Mvar
600 MW
200 Mvar
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The Impact of a Large GMD From an Operations Perspective
• Would be maybe a day warning but without specifics – Satellite at Lagrange point one million miles from earth would
give more details, but with just 30 minutes before impact– Would strike quickly; rise time of minutes, rapidly covering a
good chunk of the continent
• Reactive power loadings on hundreds of transformers could sky rocket, causing heating issues
• Power system software like state estimation could fail• Control room personnel would be overwhelmed• The storm could last for days with varying intensity• Waiting until it occurs to prepare is not a good idea
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Transient Stability Level GMD Impact Simulation
The interactive simulation shows a GMD induced voltagecollapse scenario with some protection system modeling
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GIC Flows in Eastern Interconnect for a Uniform 8.0 V/km, East-West Field
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Geographic Data Views: Displaying Net Substation Current Injections
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GICs tend to concentrate at network boundaries
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Power Flow Convergence Issues
• Integrated GIC modeling can certainly impact power flow convergence since the GIC induced reactive power losses simultaneously add lots of reactive power.
• Several techniques can help prevent divergence– Just calculating the GICs without solving the power flow– Gradually increasing the assumed electric fields to avoid
simultaneously adding too much reactive power– Only calculating the GIC transformer reactive power losses
for specified areas; reactive power doesn’t travel far– Freezing reactive control devices such as LTC taps– Solving in transient stability
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GIC Mitigation
• Engineers need tools to determine mitigation strategies– Cost-benefit analysis
• GIC flows can be reduced both through operational strategies such as opening lines, and through longer term approaches such as installing blocking devices
• Redispatching the system canchange transformer loadings,providing margins for GICs
• Algorithms are needed to provide power engineers with techniques that go beyond trial-and-error
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Photo from ATC
Research Directions
• We’ve made good progress, but still much to do!• GMD/GIC validation: While large GMDs are rare,
small ones occur regularly; magnetometers, transformer neutral current measurements and PMUs are providing the information needed for better validation
• GIC sensitivity analysis: which parameters are most important, how large of system models
• How can GICs be effectively mitigated
• Much of GIC analysis also applies to EMP E3 though on the shorter transient stability time scale
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