1. Optimal Power System Control (OPSC)
for improved system stability, optimal AGC performance, and improved tie-line control,
in interconnected or island operating mode (continental, area, sub-area, mini/micro grids)
Sub-area: BCTC
Northern
Southern Interior
Lower Mainland - Interior
Vancouver Island
Area: NPCC
NB, NS
Quebec
ME, NH, VT, MA, RI, CT
Ontario
New York
discrete-time model reference control of area frequency and tie-line power
provides optimal AGC for participating units
integrated with the ISO realtime economic dispatch and contractual inter-area tie-line flows
analyzes and schedules the tie-line net export power to maintain stable frequencies
restores normal system operation at scheduled tie-line exports after major disturbances
OPSC CIMExcel Software Inc. Slide 1 1

2. Optimal Power System Control
monitors the power generation from all power plants, and all tie-line power flows
and analyzes the LFC performance of all participating AGC units in the area
Hydroelectric
Wind
Nuclear
Fossil
Biomass/Solid Waste/Cogeneration
Combined Cycle Gas Turbine
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3. Power System Dynamics Model
The ith area is connected to the jth area by the kth tie-line (m areas and n tie-lines)
Mi = inertia of the ith area (s)
ωi = frequency of the ith area (pu)
Gi = generation of the ith area (pu)
D0i = frequency independent load of the ith area (pu)
Di = damping factor of the frequency dependent load of the ith area (pu)
Ei = net export power from the ith area (pu)
Mi d/dt ∆ωi = Gi - D0i - Di ∆ωi - Ei ∆ωi = ωi - ωset Ei = ∑p Tp ( pth tie-line connected to the ith area )
calculate Mi and identify Di from a major disturbance.
Formation of multiple internal islands (A,B,C,,, ) with modal area frequencies at the kth discrete-time step:
DA ∆ωA(k+1) = (GA0/γAGi0)(GA(k) - D0A(k)) , with modal area frequencies, ∆ωi(k) = αi (GA0DA/Gi0Di) ∆ωA(k)
DB ∆ωB(k+1) = (GB0/γBGi0)(GB(k) - D0B(k)), with modal area frequencies, ∆ωi(k) = αi (GB0DB/Gi0Di) ∆ωB(k)
DC ∆ωC(k+1) = (GC0/γCGi0)(GC(k) - D0C(k)), with modal area frequencies, ∆ωi(k) = αi (GC0DC/Gi0Di) ∆ωC(k)
Net Export Power Flows:
Ei (k) = Gi(k) - D0i(k) - (GA0/γAGi0)(GA(k) - D0A(k)) ( ith area net export in the Ath island )
Ei (k) = Gi(k) - D0i(k) - (GB0/γBGi0)(GB(k) - D0B(k)) ( ith area net export in the Bth island )
Ei (k) = Gi(k) - D0i(k) - (GC0/γCGi0)(GC(k) - D0C(k)) ( ith area net export in the Cth island )
Tie-line Power Flows:
T = A-1E where A is a r X r matrix (r < s, where s = areas in the internal island).
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4. Optimal Power System Control for AGC
P1set(j)
Eset net export
(inter-area contracts)
OPSC
Algorithm
Optimal
AGC Load
Allocation
PS(j) +
PAGC(j)
Piset(j)
APPC
power mode
Pi(j)
ωG set -
Pmset(j)
ωG(j)
Enet export(j)
pu power
setpoints for participating
units
Filter -
Sampler
Filter -
Sampler
l = m+n
~ 10 seconds
Spinning Reserve
Optimization Modes
uniform
weighted
efficiency
weighted-efficiency
∑ Pl(k)
l = m+1
ωG(t)
Enet export(t)
Filter -
Sampler
Realtime
Demand,
Import, Export
Pm+1(k)
ISO Realtime
Economic
Load Allocation
pu power for
non-participating
units
Pl(k)
Pm+n(k)
~ 5 minutes
ISO
Realtime
Pricing
Time-of-day
Scheduling and
Spinning Reserve
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5. Comparison of the Classic and OPSC Approaches for AGC-LFC
Classic Approach
General:
Control of area frequency and tie-line power
2-4 second update interval
Most Power Plants are in Frequency Control Mode
Participating AGC units with ‘speeder’ before PID
Power Plants do not measure/feedback on power
Power Plants do not achieve the AGC setpoint
Power Generation Monitoring:
None
Demand Monitoring:
Sometimes used for feedforward
Power System Total Power Generation:
Not used for AGC
Optimal AGC Unit Load Allocation:
No Spinning Reserve Considerations
Frequency Bias Setting:
Tuned each year
Integral Control Action:
Implicitly with governor ‘speeder’
Economic Dispatch:
Integrated with ISO functionality
Recovery from Major Disturbances:
Generally not used in automatic mode
Power System Dynamics Model and Simulator:
OPSC Approach
General:
Control of area frequency and tie-line power
10 second update interval - immediate reset on events
Optimal if all Power Plants are in Power Control Mode
Participating AGC units with APPC control algorithms
Power Plants measure/feedback/feedforward on power
Power Plants achieve the AGC setpoint
Power Generation Monitoring:
Each unit with a Power Generation Observer
Demand Monitoring:
Not required for OPSC
Power System Total Power Generation:
Used explicitly for AGC in the OPSC algorithms
Optimal AGC Unit Load Allocation:
Used in the OPSC algorithms (site/units) with 4 modes
10 second Spinning Reserve Considerations
Frequency Bias Setting:
Set by desired closed loop response of OPSC algorithm
Integral Control Action:
Explicitly at the AGC center - with anti-reset windup
Economic Dispatch:
Integrated with ISO functionality
Recovery from Major Disturbances:
Used in automatic mode
Power System Dynamics Model and Simulator:
Power System Simulator for identification, testing,
and what-if analysis
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6. OPSC Performance for a Mini/Micro Grid
The generation units for this mini/micro grid include, five 20 MW small hydro units, a 50 MW wind site,
a 50 MW biomass cogeneration site, and a 20 MW diesel unit.
The demand includes a 100 MW mining site, 50 MW of industrial, and 30 MW of residential.
OPSC sends power setpoints to the small hydro units approximately every 10 seconds.
The OPSC performance is shown above in response to the significant variations in demand and wind generation.
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7. NERC Sub-Area - (Ontario - IESO)
Sub-area: BCTC
Northern
Southern Interior
Lower Mainland - Interior
Vancouver Island
Area: NPCC
NB, NS
Quebec
ME, NH, VT, MA, RI, CT
Ontario (IESO)
New York
The generation capacity of this NERC Sub-Area is approximately 30 GW and includes,
Nuclear (10.5 GW)
Coal (5.3 GW)
Gas (CCGT 4.7 GW)
Hydro (7.1 GW)
Wind (1.1 GW)
Other (2.3 GW)
Multiple interconnections with Manitoba, Minnesota, Michigan, New York, and Quebec.
The demand varies in the timeframes, 10 seconds, 5 minutes and 24 hours.
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8. Optimal AGC Load Allocation - NERC Sub-Area
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9. Optimal Power System Control - NERC Sub-Area - AGC Off
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10. Optimal Power System Control – NERC Sub-Area - AGC On
(Hydroelectric sites on AGC – participating units in efficiency optimization mode)
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11. Optimal AGC Load Allocation – Efficiency Mode
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12. Optimal Power System Control – NERC Sub-Area
(AGC On - Export Trip and Recovery)
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13. Optimal Power System Control – NERC Sub-Area
(AGC On - Import Trip and Recovery)
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14. Optimal Power System Control – NERC Areas
Tie-lines
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15. Optimal Power System Control – NERC Areas
Tie-line and Area Export Schedule
3 Internal Islands are formed as a result of tie-line schedule:
Internal Island A:
ECAR
MACC
NPCC
Internal Island B:
MAIN
MAPP
Internal Island C:
ERCOT
FRCC
SERC
SPP
WECC
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16. Optimal Power System Control – NERC Areas
stable area frequencies
are possible for these scheduled tie-line flows
Internal Island A:
ECAR
MACC
NPCC
Internal Island B:
MAIN
MAPP
Internal Island C:
ERCOT
FRCC
SERC
SPP
WECC
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17. Optimal Power System Control – NERC Tie-lines
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18. Optimal Power System Control – NERC Areas
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19. OPSC Analysis and Engineering Services
for all Power Plants which participate in AGC for the area (continental, area, sub-area, mini/micro grids)
and for all area tie-line power measurement locations, and for the area AGC center.
Analysis
Data Acquisition System setup, interfacing to PLC and systems.
Signal analysis and filtering.
Estimation of the parameters for the Power System Model.
Analysis of the scheduling algorithm for the area tie-line net export power.
Design of the Power Plant AGC-LFC Performance Tests.
Testing
Testing for the Power Plant AGC-LFC Performance.
Baseline Performance monitoring and analysis for interconnected and island operation.
Simulator
Configuration for the Power System Simulator and the OPSC control algorithms.
Comparative Simulation Performance Analysis of existing and OPSC control algorithms.
Integration of the Power System Simulator at the area AGC center.
Installation of the OPSC software
For each AGC Power Plant, install the Power Generation Observer.
For each tie-line location, install the Filtering algorithms.
At the AGC center, in parallel to the existing AGC algorithms with bumpless transfer.
OPSC source code programming and testing.
Performance Trials and Acceptance Testing
Island Mode - AGC response.
Island - Interconnected Transition mode.
Interconnected with Scheduled Tie-line Changes.
Forced Island Mode.
Recovery from Forced Island Mode.
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20. Advanced Power Plant Control (APPC)
for improved stability and improved LFC performance in interconnected or island operating mode
using continuous and discrete-time non-linear model reference control technology.
Hydroelectric
Nuclear
Wind
Hydraulic Turbine Governor
(Kaplan) Pitch Optimization
Multi-Turbine Optimization
Steam Turbine Governor
Boiler Pressure and Mass
Reactor Power
PWR, BWR, Areva, CANDU, ACR
Blade Pitch
Multi-Turbine Optimization
Fossil
Biomass/Solid Waste/Cogeneration
Combined Cycle Gas Turbine
Steam Turbine Governor
Boiler Pressure and Mass
Superheater Temperature
Combustion Control
Burner Management
Steam Turbine Governor
Boiler Pressure and Mass
Multi-Fuel Combustion
Multi-Valve Turbine Flow
Multi-Steam Header
Cogeneration Optimization
Steam Turbine Governor
Boiler Pressure and Mass
Combustor Control
Combined Power
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21. Performance Analysis Toolkit
High Speed NI-DAQ
Signal Processing and Filtering
Time Series Analysis
Power Spectral Analysis
Fourier Analysis
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22. Power and Frequency Measurement - Power Generation Observer
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