Generation: Control & Economic Dispatch
2016 System Operator Seminar
Slide 2
What is Covered
Automatic Generation Control Basics• ACE Equation
Understanding FPL Generation Unit Status DisplayUnit Control Via AGCControl Performance StandardsEconomic Dispatch
• Basic Theory• Control Economic Dispatch• Study Economic Dispatch (using Economy A)
Introduction
Automatic Generation Control Basics
Slide 4
Energy Balance
GenerationDemand
Power Generated Imports
ExportsLoadsLosses
AGC BasicsSource:
Slide 5
Imbalance Conditions
Over-generation• Total Generation > Total Load• Frequency > 60 Hz• Generators momentarily speed up
Under-generation• Total Generation < Total Load• Frequency < 60 Hz• Generators momentarily slow down
AGC Basics
Slide 6
Control Responses
• Inertial Response• Frequency Bias
Characteristic• Governor & Load Response
• Regulation Control• Economic Control• System Operator
AGC Basics
Slide 7
Inertial Response
Inertia - resistance to change in rotational speedWhen generators fail to meet load
• During load increases, generator starts to slow down• During load decreases, generator starts to speed up
Generators can’t instantly stop or they will fly apartForces are present that oppose the change created by the change in load
AGC Basics
Slide 8
Governor Response
AGC Basics
Slide 9
Load Response to Frequency
Portion of system load that increases or decreases when frequency increases or decreasesMeasured in MW/0.1 HzApproximately 1 - 2 % load change for a 1% change in frequencySystem Load = 22,000 MWExample:
• Frequency Change = +/- 0.03 Hz• What is the change in system load?
• 22000 X (1 % MW/0.1Hz) X .03Hz = 66 MW• 22000 X (2 % MW/0.1Hz) X .03Hz = 132 MW
AGC Basics
Slide 10
Frequency Bias
AGC Basics
GovernorResponse
Characteristics
LoadResponse
Characteristics
Frequency Bias
Slide 11
Regulation Control
“Regulating units” are generating units that provide fine tuning which is necessary for effective system controlGovernors respond to minute-to-minute changes in load“Regulating units” correct for small load changes that cause the power system to operate above and below 60 Hz for sustained period of time
AGC Basics
Slide 12
Response Time Hierarchy for Unit Control
System Inertia ..................................................... 0 secondsFrequency Bias Characteristic ......................... < 5 seconds(Governor & Load Response)Regulation .......................................................> 30 secondsEconomic Re-Dispatch .................................... > 5 minutes
AGC Basics
Slide 13
Plant Control Using AGC
AutomaticGeneration
Control
AutomaticGeneration
Control
Turbine-generator unit
Turbine-generator unit
PowerSystemPowerSystem
Control Signal
Control Signal
Electrical Output
Electrical Output
Measurement of Electrical Output
Measurement of Electrical Output
Measurement of Tie Flow to Neighboring Systems
Measurement of Tie Flow to Neighboring Systems
Ties to Neighboring Systems
Frequency Transducer
Measurement of System Frequency
AGC Basics
Slide 14Area Control Error
Demand
Area Native Load and
LossesScheduled
Interchange
Interconnection Frequency Support
Obligation= + +
What is Area Control Error?
Control areas have the responsibility to control generation and set scheduled interchange (biased by the area’s frequency support obligation)
Slide 15Area Control Error
Mismatch Generation DemandArea Control Error
(ACE)= - =
What is Area Control Error (ACE)?
An interconnection natural regulation continually responds to all the area mismatches.ACE measures whatever mismatches exist in the presence of the interconnection’ s natural regulation.
Slide 16
Area Control Error (ACE)
The required change in generation, historically called area control error or ACE, represents the shift in area's generation required to restore frequency and net interchange to their desired values.
Area Control Error
Slide 17
FREQUENCYCOMPONENTFREQUENCYCOMPONENT
INTERCHANGECOMPONENT
INTERCHANGECOMPONENT
TIE LINE TELEMETRY ERROR
COMPONENT
TIE LINE TELEMETRY ERROR
COMPONENT
ACE
+
++
Area Control Error
Σ
FPL Area Control Error Calculation
Slide 18
Frequency Component of ACE
Area Control Error
)CorrectionError Time during (usedOffset Frequency F
Frequency Nominal F
FrequencyCurrent F
FPLfor BiasFrequency FBIAS
:where
**10
offset
nom
current
offsetnomcurrentfrequency FFFFBIASACE
Slide 19
Interchange Component of ACE
Area Control Error
Paybackt Inadverten Automatic AUPB
FPLBy Defined Schedules Dynamic FPL
Group Sharing Reserve for the Schedules RSG
UnitsOwned-Jointly toDue Schedules Dynamic JOU
replaced) is value thisactive, isScheduler Backup the(if
ITS from Schedulesn Transactio ITS
e)interchang entered(operator
eInterchang ousMiscellane ANI
FPL) toconnected flows line tieall ofsummation (the
eInterchangNet Actual ANI
:where
dynamic
misc
AUPBFPLRSGJOUITSANIANIACE dynamicmisceInterchang
Slide 20
If Tie Line Telemetry Error is positive, it means that the system had been overgenerating the previous hour because the instantaneous tie line readings were lower compared to the telemetered pulse accumulator (PAC) values
G L
FPL
G L
Other Area
ANI = 80 MW
SNI = 80 MW
ACE = 0 MW
PAC = 100 MW
Area Control Error
Tie Line Telemetry Error Component of ACE
Slide 21
If Tie Line Telemetry error is negative, it means that the system had been undergenerating the previous hour because the instantaneous tie line readings were higher compared to the telemetered PAC values
G L
FPL
G L
Other Area
ANI = 100 MW
SNI = 100 MW
ACE = 0 MW
PAC = 80 MW
Area Control Error
Tie Line Telemetry Error Component of ACE
Slide 22
Tie Line Telemetry Error Component of ACE
Calculated based on the tie line readings for the previous hour that was completed.If the calculated value of the Tie Line Telemetry Error Component is greater than 30 MWH, the value is zeroed out. This would prevent bad meter readings or bad ITS schedules having an immediate impact to AGC.The Tie Line Telemetry Error Component is usually zero UNLESS the error helps out in correcting inadvertent.
• We do not want to correct the error if it worsens our inadvertent).
Area Control Error
Slide 23
Tie Line Telemetry Error Component of ACE
Area Control Error
Flows Line Tie Inst. Actual of AverageHourly T
Readings)Meter Acc. PulseHourly (Processed Flows Line Tie T
:where
average
PAC
averagePACerror TTT
Slide 24
AGC Major Functions
Load Frequency Control: AGC matches power generation with system load while maintaining the desired frequencyEconomic Dispatch: AGC calculates the economic basepoints for the units.Reserve Monitoring: AGC takes into account the required reserve that is necessary to provide a measure of electrical security in the network based on MW reserves that are available.Performance Monitoring: AGC provides measurements of its performance based on NERC operating standards.
AGC Basics
Understanding FPL Generation Unit Status Display
Slide 26
FPL Total Generation Calculation
FPL Total Generation
Total Generation for Units Belonging to the
FPL Operating Area
Sum of Energy Purchases
St. Lucie Units (Adjustment)
Merchant Plants not Serving FPL Operating
Area
Miscellaneous Generations
ΣFPL Total
Generation
-
-
Slide 27
FPL Native Load Calculation
FPL Native Load
Total Generation for Units Belonging to the
FPL Operating Area
Sum of all Tie Flows In/Out FPL Operating Area
Miscellaneous Load
This the sum of schedules that adjusts
the typical Control Area load value so
that we could calculate FPL’s native
load.
ΣFPL Native Load-
Slide 28
Components of Miscellaneous Load
SM Schedule: Seminole Network Load• Provided for by Seminole to serve their load within the FPL Control Area
FM1 Schedule: Settlement Firm Sale to FMPACES Schedule: City of Key WestLSF Schedule: FMPA Loss Schedule
• Schedule to account for transmission losses for FMPA network serviceML Schedule: Merchant Load ScheduleKWO Schedule: West Nassau Delivery Schedule
FPL Native Load
Slide 29
FPL Native Load Calculation: Actual Data
6:40:00, -3697
6:40:00, -1088
6:40:00, 16794
6:40:00, 19402
-4000
-3500
-3000
-2500
-2000
-1500
-1000
-500
0
Time
Inte
rc
ha
ng
e &
Mis
c. L
oa
d M
W
14000
15000
16000
17000
18000
19000
20000
Ge
ne
ra
tio
n &
Lo
ad
MW
Actual Net Interchange Actual Net Interchange Control Area Generation FPL Load
FPL Native Load
Slide 30
Qualifying Facilities
A cogeneration or small power production facility that meets certain ownership, operating, and efficiency criteria established by the Federal Energy Regulatory Commission (FERC) pursuant to the Public Utility Regulatory Policies Act (PURPA).Qualifying facilities are non-utility generators.Avoided Cost - the cost the utility would incur but for the existence of an independent generator or other energy service option. Avoided cost rates have been used as the power purchase price utilities offer independent suppliers (Qualifying Facilities).
Qualifying Facilities
Slide 31
Load Rate Calculation
FPL Load is smoothed (filtered) out to remove the “noisy” nature of the load calculation. Five minutes worth of smoothed load data is collected.A program then calculates a linear regression (curve fit) of the five minute data to come up with the load rate in MW/minute.Take note that this calculation is sensitive to load variation – use the information when appropriate.Load Rate Calculation
Slide 32
Load Rate Calculation
Load Rate Calculation
24 MW/minute
19500
19600
19700
19800
19900
20000
6:45:00 6:50:00 6:55:00 7:00:00 7:05:10 7:10:10
MW
-10
0
10
20
30
40
MW
/min
ute
FPL Load FPL Load Filtered Five-Minute Sample FPL Load Rate Linear (Five-Minute Sample)
The progam perfoms a linear interpolation of the "filetered" load for a five-minute period to calculate the load rate.
Slide 33
Top of the Hour Schedule Change
THSC
Next Hour Boundary10 Minutes Before Next Hour Boundary
10 Minutes After Next Hour Boundary
Tran
sacti
on S
ched
ule
Profi
le
Time
THSC
THSC - the difference in Scheduled Power between the values at 10 minutes before the next hour and ten minutes
after the next hour.
Current Time
Slide 34
Top of the Hour Schedule Change
THSC
Current Time
Next Hour Boundary10 Minutes Before Next Hour Boundary
10 Minutes After Next Hour Boundary
Tran
sacti
on S
ched
ule
Profi
le
Time
THSC
THSC - the difference in Scheduled Power between the current time and ten minutes after the next hour.
Slide 35
Inadvertent
Energy Accounting for interconnected system is usually done by considering the amounts scheduled as being actually delivered, and any difference between scheduled and actual is INADVERTENT.
• Inadvertent energy is defined as the difference between accumulated net actual interchange and the net scheduled interchange for a control area
Inadvertent calculation is being done every hour on top of the hour after the pulse accumulators are read in.The sign convention for inadvertent and ACE implies that a positive correction term is required to correct for a positive inadvertent value
Inadvertent Payback
Slide 36
Causes of Inadvertent
Incorrect Transaction Schedules• Uncoordinated Schedules Between Entities
Inaccurate Tie Line MeteringBad Control
• Deliberate “pushing” or “pulling” of energyBad frequency control
Inadvertent Payback
Slide 37
FPL’s Inadvertent Payback Philosophy
Follow NERC standards• Limit payback to 20% of frequency bias
Done unilaterallyKeep it below +/- 150 MWhrEconomic awareness
• One-sided inadvertent payback
Unit Control Via AGC
Slide 39
How Do We Control Using AGC?
Unit Control Via AGC
Basepoint ComponentBasepoint Component
RegulationComponentRegulation
Component
Unit Control LogicUnit Control Logic
Unit Setpoint
Economic Dispatch
Operator Entry
Basepoint Schedule
ACE
Slide 40
Basepoint Component
A basepoint MW is assigned to each generator on control (AU PLC Control Mode).The unit’s basepoint could come from the following most common methods:
• Control Economic Dispatch (CE basepoint mode)• Operator-Entered Mandatory Ramp Basepoint (MR basepoint mode)
• does not care about ACE value• Operator-Entered Basepoint (BP basepoint mode)• Basepoint Schedule (BL basepoint mode) Unit Control Via AGC
Slide 41
Regulation Component
Each generator on control (AU PLC Control Mode) is also assigned a REGULATION component in order to help out with ACE.The operator has the option of controlling when the unit participates in regulation by change its ACE regulation mode:
• R - Regulate when ACE is in the normal, assist, or emergency region.• A - Regulate when ACE is in the assist or emergency region.• E - Regulate only when ACE is in the emergency region.• O - Never regulates
Unit Control Via AGC
Slide 42
What Does AGC Do With the Raw Ace?
ACE Integral• AGC also uses the raw ACE value and integrates it. The integral term of ACE
helps to correct steady-state (long term) error• This is in effect for small values of frequency deviation
CPS1 MW Bias• Using ACE and filtered frequency deviation, AGC calculates a CPS1 MW Bias• CPS1 MW Bias is a value added to AGC regulation control which will drive the
average CPS1 percentage toward a defined value (target = 145%)• This control is only effective when the filtered frequency deviation is larger
than a definable threshold (when frequency deviation is close to zero it is not practical to attempt to bias AGC regulation)
• FPL filtered frequency deviation threshold for CPS1 bias correction is 0.005 Hz• The calculated MW bias is used in place of the ACE Integral term in
calculation of the regulation action
Unit Control Via AGC
Slide 43
Regulation Component Processing
Raw ACE
PredictedACE
Next 2-Minutes Transaction Schedules
IntegratedACE
ProportionalACE
Frequency DeviationCPS1 MW Bias
IntegratedACEOR
PLC Regulation Logic
Unit Control Via AGC
Slide 44
Regulation Component
Depending on the ACE regulation region, some PLCs may be eligible to participate in regulation while others may not.Processed ACE is allocated according to the regulation participation factors.After allocation, the PLC regulation components are filtered.
Unit Control Via AGC
Slide 45
Regulation Component
The regulation component is added to each PLC basepoint to obtain the desired generation for that PLC. Next, raise/lower MW control actions are computed for each PLC.Once the desired generation for a PLC has been determined, the change in unit MW output that will meet the desired generation for the PLC is calculated. This takes into account unit response rates and unit high/low regulation limits.
Unit Control Via AGC
Slide 46
Regulation Region Indicator (RRI)
The Area Control Error (ACE) is computed. Based on this value, the regulation region for area control response is determined. AGC recognizes four possible regulation regions:
• Deadband (0-10 MW)• Regulate (10-60 MW)
• NORMAL• INTEGRAL
• Assist (60-200 MW)• Emergency (200+ MW)
There is also a limit called ACE Permissive Limit - If ACE exceeds this level pulses in the direction to worsen ACE are blocked. It should be noted that as this value is reduced, ACE will increasingly drive the output of the system (60 MW)
Unit Control Via AGC
Slide 48
Regulation Region Indicator (RRI)
Unit Control Via AGC
Slide 49
Regulation Region Indicator (RRI)
Unit Control Via AGC
Control Performance Standards
Slide 51
• CPS1 is a statistical measure of ACE variability and its relationship to frequency error
• It is intended to provide a frequency sensitive evaluation of how well demand requirements are met
• Calculated over a sliding 12-month period• NOTE: ACE reported to NERC for CPS1 should not include
inadvertent.
Control Performance Standards
CPS1 Review
Slide 52
12-Month Compliance Factor
boundfrequency targeteda from derivedconstant
BiasFrequency
ErrorFrequency of Average Minute-Clock
ACE NERC of Average Minute-Clock
Factor ComplianceMonth -12
:where
*10
1
12
21
12
12
i
i
i
month
ii
imonth
month
B
F
ACE
CF
FB
ACEAVG
CF
Control Performance Standards
Slide 53
CPS1 Calculation
100*21 1212 monthmonth CFCPS
Good scores range from 100% to 200%
Control Performance Standards
Slide 54
CPS1 Review
Control areas are not penalized when ACE benefits system frequencyNegative ACE means you are under-generating:
• If frequency is high (greater than 60 Hz.), it is OK to have a small negative ACE because you are helping out the interconnection.
Positive ACE means you are over-generating:• If frequency is low (less than 60 Hz.), it is OK to have a
small positive ACE because you are helping out the interconnection.
Control Performance Standards
Slide 55
CPS1 Review
-300.00
-200.00
-100.00
0.00
100.00
200.00
300.00
-0.16 -0.14 -0.12 -0.10 -0.08 -0.06 -0.04 -0.02 0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16
-200% -100% 50% 100% 250%
Control Performance Standards
Region of above 60 Hz and negative
ACE
Region of below 60 Hz and positive ACE
Slide 56
CPS1 Charts
Scheduled Mw
Actual Mw
Poor Control
Insufficient AS
Same CPS1
Hurting Frequency Helping Frequency
Regulation
Imbalance
Reserves
One Hour
Control Performance Standards
Slide 57
How Are We Doing With CPS1?
Control Performance Standards
Slide 58
CPS2 Review
CPS2 is a “safety valve” standard that was put in place when CPS was developedConcern was that if CPS1 was the only regulating standard, Control Areas would:
• Grossly over or under generate (as long as it was opposite frequency)
• Get very good CPS1 scores• Impact neighbors with excessive flows
Control Performance Standards
Slide 59
CPS2 ReviewCPS2 is a measure of average ACE over all 10-minute periods in a monthUnder CPS2, ACE is limited to a “regulating road”The width of the “regulating road” proportional to the Control Area’s sizeCPS2 is a statistical measure designed to limit unacceptably large net unscheduled power flows.
• CPS2 is designed to bound ACE ten minute averages.
L10 is the term used to describe the width of the “regulating road”
• L10 is a constant determined particular to every interconnection. Control Performance Standards
Slide 60
L10 Formula
boundfrequency targeteda from derivedconstant
Settings BiasFrequency ction Interconne of Sum
BiasFrequency Area Control
ACE NERC of bounds minute-10
:where
1010*65.1
10
10
1010
s
i
si
B
B
L
BBL
Control Performance Standards
For FPL Control Area, L10 = 114.21 MW
Slide 61
FRCC 2006 CPS2 Bounds
Control Performance Standards
Slide 62
CPS2 Calculation
1010 )( LACEAVG
Good scores range from 90% to 100%
Control Performance Standards
Slide 63
CPS2 Review
CPS2 states that for each 10-minute period, the average ACE for a Control Area must be less than the L10 of that Control Area
Any clock 10-minute period greater that L10 (whether it’s 1 MW more or 100 MW more) is a violationThe minimum acceptable CPS2 for a month is 90%
• This means that on average, a Control Are may have roughly one violation every other hour and still pass CPS2
Actual L10 usually change slightly each year based on Bias calculations
Control Performance Standards
Slide 64Control Performance Standards
Compliance
Control Compliance Rating = PASSif CPS1 100% and CPS2 90%Control Compliance Rating = FAILif CPS1 < 100% and CPS2 < 90%
Slide 65
What is Displayed to the Operator
Generation Area Status (CPS data in the ACE data block).
• This block contains critical CPS data that lets you know the immediate status of the control area.
• Under the ACE limits associated with the ACE graphic are the high and low CPS ACE limit.
• For the current frequency deviation, values of ACE within the limits should result in passing values for CPS1 and CPS2.
Control Performance Standards
Economic Dispatch Basics
Slide 67Economic Dispatch
Economic Dispatch
The distribution of total generation requirements among alternative sources for optimum system economy with due consideration of both incremental generating costs and incremental transmission losses.Basically, the objective of Economic Dispatch is to operate the power system at minimum $/HR cost at all times.The generation is allocated within AGC using computed economic base points and economic participation factors.
Slide 68
Projected Natural Gas Prices
Economic Dispatch
*units in 2004 $ per thousand cubic feet
Slide 69
Projected Electric Capacity Additions
Economic Dispatch
*units in gigawatts
Slide 70
Projected Production Costs
Economic Dispatch
*units in 2004 $ per million Btu
Slide 71
Load and System Incremental Costs
Economic Dispatch
Slide 72
Economic Dispatch
Turbine-generator unit
Turbine-generator unit
Turbine-generator unit
P1
P2
P3
PR
The problem is to determine the P1, P2 and P3 dispatch levels to be able to serve PR in the most economical way. For this example, let’s say we have a requirement of PR = 500 MW.
PR = received power
P1, P2, P3 = net power output of each generator
Economic Dispatch Algorithm
Slide 73
Economic Dispatch
• For the 3 unit example, the economic dispatch problem is to...minimize F1 + F2 + F3where F1 = F1(P1)
F2 = F2(P2)F3 = F3(P3)
• F1 is the cost ($/MWhr) to operate Generator 1 at power output P1.
• F2 is the cost ($/MWhr) to operate Generator 2 at power output P2.
• F3 is the cost ($/MWhr) to operate Generator 3 at power output P3.
Economic Dispatch Algorithm
Slide 74
Generator Costs
There are many fixed and variable costs associated with power system operation.Generation is major variable cost.For some types of units (such as hydro and nuclear) it is difficult to quantify.For thermal units it is much easier. There are four major curves, each expressing a quantity as a function of the MW output of the unit.
Economic Dispatch
Slide 75
Generator Costs
Input-Output (IO) Curve• Shows relationship between MW output and energy input in Mbtu/hr.
Production Cost Curve• Input-output curve scaled by a fuel cost expressed in $/Mbtu which
results in production cost in $/hr.Heat-Rate Curve
• Shows relationship between MW output and energy input (Mbtu/MWhr)
Incremental (Marginal) Cost Curve• Shows the cost to produce the next MWhr
Economic Dispatch
Slide 76
Economic Dispatch
PMIN PMAX
Output Power (MW)
Inp
ut
Pow
er
(Mb
tu/h
r) • Each generator has an Input/Output curve.
• The y-axis is the thermal input power in Mbtu/hr.
• The x-axis is the electrical output power in MW.
• The valve points are usually ignored in economic analysis.
Input-Output Curve
Valve Points (Steam)
Slide 77Economic Dispatch
Pout = Output Power (MW)
Pro
du
ctio
n C
ost
($
/hr)
The Production Cost Curve
hrMbtuhr
Mbtu $$*Cost Production
• If we multiply, the IO Curve with a constant fuel cost in $/Mbtu, the result is the Production Cost in $/hr.
Slide 78Economic Dispatch
Pout = Output Power (MW)
Heat
Rate
(M
btu
/MW
hr)
The Heat Rate Curve
MWhr
Mbtu
MWhr
Mbtu
RateHeat
• If we divide, the IO Curve with the corresponding output MW, we get the unit’s Heat Rate.
• Unit heat rate characteristics are a function of unit design parameters such as initial steam conditions, stages of reheat and the reheat temperatures.
Prated
Slide 79Economic Dispatch
Pout = Output Power (MW)
Pin =
In
pu
t Po
wer
(Mb
tu/h
r)Slope of the IO Curve
Run = Pout
Rise
= P
in
RateHeat lIncrementa/
MWhr
Mbtu
MW
hrMbtu
P
P
Run
RiseSlope
out
in
• If we take the slope (derivative) of the IO curve at every point, we will come up with the unit’s incremental heat rate.
• The generator IO curve is usually approximated by a parabolic curve – therefore, the derivative is a straight line.
Slide 80
Economic Dispatch
PMIN PMAX
Output (MW)
$/M
WH
R
• If we multiply the fuel cost and the IHR Curve, we will have the Incremental Cost Curve.
• This is the curve we use for Economic Dispatch!
Incremental Cost Curve
Slide 81
Example: Turkey Point No. 1UNIT BASE EFFICIENCIES
February-06PROJECTED Summer Off Control Continuous
HEAT RATE On Control Summer Heat
BE (BTU/KWH) GAF Continuous Capacity Input OIL HEAT INPUT EQUATION GAS HEAT INPUT EQUATIONOIL GAS (MW) (MW) Factor
0.945 9792 10330 1.055 381 385 1.0095 304714 + 7258.26 * P + 3.1436 * P^2 321473 + 7657.46 * P + 3.3165 * P^2
Economic Dispatch
0
500
1000
1500
2000
2500
3000
3500
0 50 100 150 200 250 300 350 400 450
MW
Mb
tu/h
r
0
5
10
15
20
25
30
35
Mb
tu/M
W
IO Curve (Mbtu/hr) Heat Rate Curve (Mbtu/MW) Incremental Heat Rate (Mbtu/MWhr)
Slide 82
Turbine-generator unit
Turbine-generator unit
Turbine-generator unit
P1
P2
P3
High Voltage Transmission
System
I2R LOSSES
PLOAD
Economic Dispatch
Effect of Penalty Factor
Slide 83
Economic Dispatch
Since FPL’s load center is located in South Florida, units in the north have a higher penalty factors compared to units in the south.
Penalty Factor
Slide 84Economic Dispatch
Penalty FactorsUnits nearer to the load center: Units farther from the load center:
Penalty Factors are calculated by the Network Applications
Slide 85Economic Dispatch
$/MWHR
MW
$/MWHR
MW200 200
NO PENALTY FACTORS
Two identical units with the same Incremental Cost Curve were dispatched at the same MW level.
Penalty Factors
Slide 86Economic Dispatch
$/MWHR
MW
$/MWHR
MW270 130
WITH PENALTY FACTORS
The Incremental Cost Curves were shifted, the Generator with a lower penalty factor had a higher dispatch level compared to the
unit with a lower penalty factor.
Pf = 0.9 Pf = 1.1
Curve shifted up!Curve shifted down!
Penalty Factors
Slide 87
Incremental Cost CurvesIn AGC, we model the unit’s IHR, we have one curve per fuel type.
The program calculates the incremental cost curve based on fuel cost and penalty factors and the IHR curve selection.
Economic Dispatch
Slide 88Economic Dispatch
Solving the Economic Dispatch Problem
The Incremental Cost Curve is used to determine the optimal (most economical) dispatch for Generators 1, 2, and 3.In theory, to obtain the optimal dispatch, each unit should be operated so that they have the same incremental cost.Economic Dispatch uses an iterative solution technique that includes finding the value of Incremental Cost, Lambda (λ) that results in all units on dispatch operating at the same Incremental Cost.
Slide 89Economic Dispatch
P(MW)
F1(P)/P
P(MW)
F2(P)/P
P(MW)
F3(P)/P
Determine power generation requirement, PR=500 MW; guess a starting Lambda
Solving the Economic Dispatch Problem
Slide 90Economic Dispatch
P(MW)
F1(P)/P
P(MW)
F2(P)/P
P(MW)
F3(P)/P
P1
P2
P3
PT=100+250+100=450
Project the corresponding MW value for each Generator and
sum up the values (PT); compare this sum to the
generation value needed to be dispatched (PR=500).
100 250 100
Solving the Economic Dispatch Problem
Slide 91Economic Dispatch
P(MW)
F1(P)/P
P(MW)
F2(P)/P
P(MW)
F3(P)/P
Compare to PR
Adjust P1
P2
P3
Adjust up or down until
P1 + P2 + P3 = PR
100 250 100
Solving the Economic Dispatch Problem
Slide 92Economic Dispatch
P(MW)
F1(P)/P
P(MW)
F2(P)/P
P(MW)
F3(P)/P
P1
P2
P3
120 275 105
PT=120+275+105=500
Iteration is stopped when PT = 500
Solving the Economic Dispatch Problem
Slide 93
Live Example
Economic Dispatch
http://pw.elec.kitami-it.ac.jp/ueda/java/ELD/
For these examples... observe what happens when the units are at their limits!
Slide 94
Economic Dispatch
The purpose of Economic Dispatch is to minimize the production cost of on-line generation. For example, if we need to serve 300 MW...
UNIT 1 UNIT 2 SYSTEM
MW Unit Lmda. Prod. Cost MW Unit Lmda. Prod. Cost Prod. Cost0 30 5700 300 50 15250 2025050 35 6750 250 45 12750 19500
100 40 8750 200 40 10500 19250150 45 11000 150 35 8500 19500200 50 13500 100 30 6750 20250250 55 16250 50 25 5250 21500300 60 19250 0 20 4000 23250
Do we know what we are doing?
Slide 95
UNIT 1 UNIT 2 SYSTEM
MW Unit Lmda. Prod. Cost MW Unit Lmda. Prod. Cost Prod. Cost0 30 5700 300 50 15250 2025050 35 6750 250 45 12750 19500
100 40 8750 200 40 10500 19250150 45 11000 150 35 8500 19500200 50 13500 100 30 6750 20250250 55 16250 50 25 5250 21500300 60 19250 0 20 4000 23250
Economic Dispatch
Optimum dispatch reflects the lowest system production cost for on-line
units; also, notice that the incremental cost for each unit is the
same.
Do we know what we are doing?
Slide 96
Economic Dispatch
UNIT 1 UNIT 2 SYSTEM
MW Unit Lmda. Prod. Cost MW Unit Lmda. Prod. Cost Prod. Cost0 30 5700 300 50 15250 1525050 35 6750 250 45 12750 12750
100 40 8750 200 40 10500 10500150 45 11000 150 35 8500 8500200 50 13500 100 30 6750 6750250 55 16250 50 25 5250 5250300 60 19250 0 20 4000 4000
If unit 1 was not committed at all, unit 2 fulfills the load requirement
with a lower system production cost!
Do we know what we are doing?
Control Economic Dispatch
Slide 98
Control Economic Dispatch
Control Economic Dispatch (CED)• CED provides economic basepoints for dispatchable units on AGC control. AGC uses these
basepoints for control.
Units that participate are:• Online and available for CED.• On AGC control.• Have economic data such as Incremental Cost Curves (ICC) available.
Control Economic Dispatch
Slide 99
Generation Requirement
Net Area Generation Requirement =
Filtered Load Estimate- FIXED GENERATION (Generation of non-Economic Dispatch
Units, Actual Generation of the MAN PLCs Basepoints of the AV, BP, EC, EX, and BL PLCs, Miscellaneous Generation)
- Miscellaneous Load+ Net scheduled interchange+ Net Dynamic Interchange from internally operated jointly-
owned units+ Net Dynamic loads+ Inadvertent Payback+ Reserve Sharing Group Schedule+ Predicted Scheduled Interchange change+ Predicted Load change+ FPL Dynamic Loads
Control Economic Dispatch
Slide 100
Generation Requirement
Operator decisions impact generation
requirement; in this example, another unit is
added for regulation!
Control Economic Dispatch
Slide 101
Control Economic Dispatch
Valid status conditions resulting from an Economic Dispatch are as follows:
• OK: No Limits Were Violated• Generation Requirement Too Low• Generation Requirement Too High• Reserve Requirement Can’t Be Met
The resulting LAMBDA is the area incremental cost in $/MWHR.The available units' operational economic limits are determined by the economic limits as well as current generation and response rate limits.
Control Economic Dispatch
Slide 102
LambdaThe equation for lambda is…
Lambda = [ Fuelpart + NOXpart + SO2part + CO2part ]*PENF / 100
Where:
Fuelpart = (Dheat * Fcost + Mdel) * Wtfuel
NOXpart= Costs associated with Nitrous Oxide output at current incremental heat with scrubbing taken into account.
SO2part = Costs associated with Sulfur Oxide output at current incremental heat with scrubbing taken into account.
CO2part = Costs associated with Carbon Dioxide output at current incremental heat with scrubbing taken into account.
Dheat = Fuel units per MWH
Fcost = Price per fuel unit
Mdel = Maintenance cost per MWH
Wtfuel = Weighting factor for fuel
Penf = Penalty factor attributed to the unit
Control Economic Dispatch
Advisory Economic Dispatch
Slide 104
Advisory Economic Dispatch
Advisory Economic Dispatch (AED)• AED provides advisory economic basepoints for all online, dispatchable units.• AED basepoints are advisory only, they are not used for AGC control purposes. • The AED basepoint for a unit that is not controllable by AGC can be communicated to the
plant operator, who can place the unit at the desired level. Units that participate are:
• Online and available for AED.• Have economic data such as Incremental Cost Curves (ICC) available.
Advisory Economic Dispatch
Study Economic Dispatch
107
Questions?
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