OPSC CIMExcel Software Inc. Slide 1

OPSC CIMExcel Software Inc. Slide 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)

Area: NPCCNB, NS

Quebec

ME, NH, VT, MA, RI, CT

Ontario

New York

Sub-area: BCTCNorthern

Southern Interior

Lower Mainland - Interior

Vancouver Island

• 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


Optimal Power System Control

Hydroelectric

Fossil Biomass/Solid Waste/Cogeneration

NuclearWind

Combined Cycle Gas Turbine

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

CIMExcel Software Inc. Slide 3

Power System Dynamics ModelThe 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 i th 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 k th 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).


Optimal Power System Control for AGC

P1set(j)

ISO RealtimeEconomic

Load Allocation

ωG(j)

ωG set

OPSCAlgorithm

RealtimeDemand,Import, Export

~ 10 secondsFilter -

Sampler

ωG(t)

Optimal AGC LoadAllocation Pmset(j)

Piset(j)PS(j)

ISORealtimePricing

Pm+1(k)

Pm+n(k)

Pl(k)

∑ Pl(k)

l = m+1

l = m+n

+

-

PAGC(j)

~ 5 minutes

pu powersetpoints for participating

units

Time-of-dayScheduling and

Spinning Reserve

pu power for non-participating

units

APPCpower mode

Pi(j)

Spinning Reserve

Optimization Modes• uniform• weighted• efficiency• weighted-efficiency

Filter - Sampler

Eset net export

(inter-area contracts)

Enet export(t)

Enet export(j)

Filter - Sampler


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 setpointPower Generation Monitoring:• NoneDemand Monitoring:• Sometimes used for feedforwardPower System Total Power Generation:• Not used for AGCOptimal AGC Unit Load Allocation:• None• No Spinning Reserve ConsiderationsFrequency Bias Setting:• Tuned each yearIntegral Control Action:• Implicitly with governor ‘speeder’Economic Dispatch:• Integrated with ISO functionality Recovery from Major Disturbances:• Generally not used in automatic modePower System Dynamics Model and Simulator:• None

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 setpointPower Generation Monitoring:• Each unit with a Power Generation Observer Demand Monitoring:• Not required for OPSCPower System Total Power Generation:• Used explicitly for AGC in the OPSC algorithmsOptimal AGC Unit Load Allocation:• Used in the OPSC algorithms (site/units) with 4 modes• 10 second Spinning Reserve ConsiderationsFrequency Bias Setting:• Set by desired closed loop response of OPSC algorithmIntegral Control Action:• Explicitly at the AGC center - with anti-reset windupEconomic Dispatch:• Integrated with ISO functionalityRecovery from Major Disturbances:• Used in automatic modePower System Dynamics Model and Simulator:• Power System Simulator for identification, testing, and what-if analysis


OPSC Performance for a Mini/Micro GridThe 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.


NERC Sub-Area - (Ontario - IESO)

Area: NPCCNB, NS

Quebec

ME, NH, VT, MA, RI, CT

Ontario (IESO)New York

Sub-area: BCTCNorthern

Southern Interior

Lower Mainland - Interior

Vancouver Island

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.


Optimal AGC Load Allocation - NERC Sub-Area

0123456789

101112131415161718192021222324252627282930313233343536373839404142434445

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000

AGC (MW)

Par

tici

pan

t U

nit


Optimal Power System Control - NERC Sub-Area - AGC Off


Optimal Power System Control – NERC Sub-Area - AGC On(Hydroelectric sites on AGC – participating units in efficiency optimization mode)


Optimal AGC Load Allocation – Efficiency Mode


Optimal Power System Control – NERC Sub-Area(AGC On - Export Trip and Recovery)


Optimal Power System Control – NERC Sub-Area(AGC On - Import Trip and Recovery)


Optimal Power System Control – NERC Areas

Tie-lines



Tie-line and Area Export Schedule

Internal Island A:• ECAR• MACC• NPCC

Internal Island B:• MAIN• MAPP

Internal Island C:• ERCOT• FRCC• SERC• SPP• WECC

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

stable area frequenciesare possible for these scheduled tie-line flows


Optimal Power System Control – NERC Tie-lines




OPSC Analysis and Engineering Servicesfor 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

1. Data Acquisition System setup, interfacing to PLC and systems.

2. Signal analysis and filtering.

3. Estimation of the parameters for the Power System Model.

4. Analysis of the scheduling algorithm for the area tie-line net export power.

5. Design of the Power Plant AGC-LFC Performance Tests.

Testing

6. Testing for the Power Plant AGC-LFC Performance.

7. Baseline Performance monitoring and analysis for interconnected and island operation.

Simulator

8. Configuration for the Power System Simulator and the OPSC control algorithms.

9. Comparative Simulation Performance Analysis of existing and OPSC control algorithms.

10. Integration of the Power System Simulator at the area AGC center.

Installation of the OPSC software

11. For each AGC Power Plant, install the Power Generation Observer.

12. For each tie-line location, install the Filtering algorithms.

13. At the AGC center, in parallel to the existing AGC algorithms with bumpless transfer.

14. OPSC source code programming and testing.

Performance Trials and Acceptance Testing

15. Island Mode - AGC response.

16. Island - Interconnected Transition mode.

17. Interconnected with Scheduled Tie-line Changes.

18. Forced Island Mode.

19. Recovery from Forced Island Mode.


Advanced Power Plant Control (APPC)

Hydroelectric

Fossil Biomass/Solid Waste/Cogeneration

Nuclear Wind

Combined Cycle Gas Turbine

for improved stability and improved LFC performance in interconnected or island operating modeusing continuous and discrete-time non-linear model reference control technology.

• Hydraulic Turbine Governor• (Kaplan) Pitch Optimization • Multi-Turbine Optimization

• Steam Turbine Governor• Boiler Pressure and Mass• Reactor Power• PWR, BWR, Areva, CANDU, ACR

• 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

• Blade Pitch • Multi-Turbine Optimization


Performance Analysis Toolkit

High Speed NI-DAQ Signal Processing and Filtering Time Series Analysis

Fourier Analysis Power Spectral Analysis


Power and Frequency Measurement - Power Generation Observer

Documents

OPSC CIMExcel Software Inc. Slide 1