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Remedial Action Schemes: Practical Solutions for Power System Stability Problems. Scott Manson, PE March, 2011. What Dictates Power System Stability?. Frequency Response Characteristic Major Disturbances Volt/ MVAr Margins Frequency/MW Margins Economics Undesired Oscillations. - PowerPoint PPT Presentation
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Copyright © SEL 2010
Remedial Action Schemes:Practical Solutions for Power System
Stability Problems
Scott Manson, PE
March, 2011
What Dictates Power System Stability?
• Frequency Response Characteristic
• Major Disturbances
• Volt/MVAr Margins
• Frequency/MW Margins
• Economics
• Undesired Oscillations
Governors/Turbines Simply Can’t Respond Instantly
0.000 2.000 4.000 6.000 8.000 10.000 12.000 14.000 16.000 18.00091.000
92.000
93.000
94.000
95.000
96.000
97.000
98.000
57.00
58.00
59.00
60.00
61.00
62.00
63.00
Time (Secs)
Pow
er (M
W)
Blue – Mechanical Power
Black –Speed
Note lag in response
Red – Electrical Power
Typical Governor Controller
+
+ –
s1
1.0
vmin
–
+
Cf
+
Cp
Generator Power
Pmwset
Nset
Turbine Speed
Nref
Kimws
1R
Kigov
Kpgovs
1
1 sTelec
1Kturb
KjrlPjrl
wfnl Mjrl
Rate Limited Tracking
Rjrl
1
1 sTjrfPgen
s3
1.0
0
KijrlKpjrl
s
s2
1.0
0
KiloadKpload
s
Plimwfnl
Kturb
11 sTth
1 sTsa1 sTsb
s7 s8Plim
11 sTact
s4
1 sTfa1 sTfb
s5
1 sTc1 sTb
s6
wfnl
Pmech
fn
ft
fj
Low
Val
ue S
elec
t
X
Speed**Dm
–+
++
–
–+
+
+
+
++
–
–
+
+
–
s9
s10
s0
WGOV1
Frequency Depressions
J=
Power In –w
S Power OutSDf/dt
• Most turbines control packages trip off at ~ 57.5 Hz to protect themselves from damage
• Large, Expensive Motors trip for same reason
• Will Cascade into uncontrolled blackouts
frequency decay rate proportional to the magnitude of the power deficit
300002500020000150001000050000
Time (ms)
454647484950
Mag
nitu
de (M
ag)
Case 1 Case 2
Frequency Response Characteristic• Many different definitions and names
throughout the world♦ R, FRC, dF/dP, etc
• Some countries (not US) define generator FRC requirements
• Effects Dominated by:♦ Load composition♦ System Inertia♦ Generator Tuning
Frequency Response Characteristic (FRC) Example for large offshore NGL plant
Sudden increase of 0.3 pu load
Three common FRC Variants
• Point A - ‘Transient’ FRC = 50 (0.3)/ (50-48.7) = 11.5
• Point B – Locked Rotor FRC = Extraction mode FRC =
50 (0.3)/ (50-48) = 7.5
• Point C – ‘System Long Term FRC’ = ‘System Droop Characteristic’ =
50 (0.3)/ (50-49.4) = 25
What does FRC tell you about a Power System?
• A quantity of ‘stiffness’
• Example: Long Term FRC ♦ 25*150 MW/50Hz = 75 MW/Hz♦ 75 MW of load will reduce system frequency
by 1 Hz
• Extraction Mode FRC = 22.5 MW/Hz
• Transient FRC = 34.5 MW/Hz
Solutions for a Poor FRC
• Governor tuning
• Add Inertia
• Limit electronic loads
• More Synchronous Machines
• BIG Battery Backed Statcom
• Load Shedding
• Generation Shedding/Runback
SEL Project to improve Power Quality Presidio, TX (By Controlling Some Big
Batteries)
Power Corridor Transport Limits
• Out of Step (OOS) Behavior Lethal to machines and power systems
• Thermal limits must be obeyed to prevent conductor damage
Jim Bridger Power Plant – Long History of Severe Faults and OOS
behavior
Power System OverviewBoise
Midpoint
Portland
GoshenKinport
Borah
Adel
Hunt
Salt Lake
Jim Bridger
500 kV345 kV230 kV138 kV
Legend:
SEL RAS Protection Required
• Prevent loss of stability caused by♦ Transmission line loss♦ Fault types♦ Jim Bridger Plant output levels
• WECC requires Jim Bridger output reduced to 1,300 MW without RAS
Stability Studies Determine RAS Timing Requirements
• Total time from event to resulting action must not exceed 5 cycles
• 20 ms available for RAS, including inputde-bounce and output contact
JB RAS Also protects against…• Subsynchronous resonance (SSR)
protection – capacitor bypass control
• Transmission corridor capacity scheduling limits
Dynamic Remedial Action for Idaho Power Co.
Oregon
Idaho
Wyoming
Utah
Nevada
Montana
California
Portland
BoisePath 17
J
Substation A
B CD
EG
Salt Lake City
Washington
380-mile drive between Substation A and Substation J
138 kV230 kV345 kV500 kV
Idaho Power System Conundrum
• Maintain the stability, reliability, and security
• Operate system at maximum efficiency
• Prevent permanent damage to equipment
• Minimal Capital expenditures
• Maximize Revenue
• Serve increasing load base
RAS Was Lowest Cost Solution
• New transmission line: $100s of millions
• New transmission substation: $10s of millions
• This project: approximately $2 million
RAS Functional Requirements
• Protect lines against thermal damage
• Optimize power transfer across critical corridors
• Predict power flow scheduling limits dynamically
• Follow WECC requirements
• Track Changing power system topography
• 20 ms response requirement
RAS Actions Based on Combinations of Factors
• N events (64)
• J states (64)
• System states (1,000)
• Arming level calculation
• Action tables combinations (32)
• Crosspoint switch (32x32)
Gain Tables Allow Operations to Adjust RAS Performance for Any System Event
• 7 gain entries used in arming level equation♦ 64 N events♦ 32 actions♦ 1,000 system states♦ 4 seasons
• 8,192,000 possible gains per gain entry
• 57,344,000 total gains
RAS Gains Configured From HMI
Most Sophisticated RAS in the World exists in South Idaho
Major Disturbances Put Power Systems at Risk
• Faults♦ Critical Clearing Time to prevent OOS♦ Fault Type♦ Protection speed♦ Fast breakers
• Load startup or trip (FRC problem)
• Generator trip (FRC problem)
Generator Trip at Chevron Refinery Cause Massive Financial and
Environment Problems
Generation Station No. 1
Production Plant No. 1 Load ~ 120MW
Generation Station No. 2 & Prod. Plt 2 Load ~ 40MW
Generation Station No. 3 & Prod. Plt. No. 3 Load ~ 60MW
Fig. 1 – Simplified One-Line Asian Oil Production Complex
Asian Electrical Operating Company (National Grid)
4 x 32 MW ea 3 x 34.5 MW ea.
2 x 105 MW ea.
Potential for power system collapse
Generation Tripping Remediated by sub-cycle load shedding Techniques
Invented at SEL
Crosspoint Switch
f
tCB
Opens
Tripping Outputs
TriggerInputs
X
Trip G2
N5
N4
XN3
XN2
N1
Trip G1
Output RemediationContingency
Trip G3
X
Trip G4
X
Bypass C1
X
Bypass C2
X
X
X XX
X
Preloaded and Ready to Go
Generation Tripping Problem Requires a sub-cycle Load Shedding Scheme
Three main techniques for Load Shedding
• Contingency-based (aka ‘FLS’)♦ Tie line
♦ Bus Tie
♦ Generator
♦ Asset Overloads
• U/F based♦ Traditional technique in relays (lots of problems)
♦ Enhanced SEL technique, generally a backup to contingency-based system
• U/V based
Contingency Based Load Shed Systems for Chevron Plant
• Sub cycle response time prevent frequency sag
• Advises operator of every possible future action
• Expandable to thousands of sheddable loads with modern protocols
• Tight integration to existing protective relays
Contingency Based Load Shed system for Chevron
• Must have live knowledge of machine IRMs, Spinning Reserves, Power output
• initiating event is the sudden loss (circuit breaker trip) of a generator, bus coupler breaker, or tie breaker.
• perform all of their calculations prior to any contingency event
• System topology tracking
Typical Volt/VAR Stability problems
• Typical problems♦ Fault induced long term suppressed voltage
conditions♦ Large Motor Starting Risk Plant blackouts
• Typical Solutions♦ Dynamic control of exciters on large
synchronous motors♦ FACTS devices♦ Misc power quality improvement electronics
Low Cost Solution: Controlling Exciters on 15 MVA SM on a 700 MW GOSP preserves VAR margins
11
12
13
14
15
16
0 100000 200000 300000 400000
13.8kV Motor Bus Voltage (Starting Motor Bus Only)
Electrotek Concepts® TOP, The Output Processor®
Magn
itude
(Mag
)
Time (ms)
MBUS2V - VAR Control MBUS2V - Voltage Control Only
MBUS2V - Voltage Control plus Gen
How to contain a Voltage Collapse?
• Increase generation – reduce demand, match supply and demand
• Increase reactive power support
• Reduce power flow on heavily loaded lines (use Flexible AC Transmission Systems)
• Reduce OLTC at distribution level, to reduce loads and avoid blackouts (Brownout)
Frequency/MW Margins
• Problem1: Long Term Problem. Caused by Insufficient Reserve Margins (RM) of generation. Solution: Add more generators.
• Problem2: Short Term Problem. Caused by insufficient Incremental Reserve Margin (IRM) of generators. ♦ Solution1: RAS load/generation shedding♦ Solution2: Machines with larger IRM
Typical Steam Turbine IRM characteristic
Output (%)
Time (Seconds)
100 %
500 0
0 %
Typical IRM values
• Steam Turbines: 20-50%
• Combustion Turbines ♦ Single Shaft Industrials: 5-10%♦ Aero Derivatives: 10 – 50%
• Hydro Turbines: 1 - 25%
Economics Affecting Stability
• Danger: Fewer, larger generators♦ Less expensive, more efficient♦ More risk upon losing one generator
• Economic Dispatch Contradicting Stability Optimization♦ NIMBY: Local Thermal/ Remote Hydro plants♦ MW transactions across critical corridors put
plants or system islands at risk
Solution: Active Load Balancing and Tie flow control for Optimal Stability
• Economic Dispatch (Low Risk Scenarios)♦ Tie line flows (MW) per contracted schedule
♦ Distributes MW between units per Heat Rate
• Tie-line closed (High Risk Scenarios):♦ Control intertie MW to a user defined low value
♦ Distributes MW between units, equal % criterion
• Tie-line open (Islanded Operation – high risk) ♦ Control system frequency to a user defined set-point
♦ Distributes MW between units , equal % criterion
Common PowerMAX Screen:AGC/VCS Interface
Common PowerMAX Screen:ICS Interface
Unwanted Oscillations
• Explain Spectrum of a power system
• Sub Synchronous Resonance (SSR)♦ First detected in 1970’s during commissioning
of high speed/gain exciters♦ Mechanical/Electrical Mode Interaction
Shaft oscillation modes
Heavily Series compensated lines
• Improperly Reactive Compensation in Exciters
Power System Stabilizers• Provide Damping based on two possible
input types:♦ Frequency (Hz)/Speed (rpm) – US♦ Power (MW) - Europe
Any Questions?