Generation: Control & Economic Dispatch 2016 System Operator Seminar.

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


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


Slide 22


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


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



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?


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


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


Slide 43

Regulation Component Processing

Raw ACE

PredictedACE

Next 2-Minutes Transaction Schedules

IntegratedACE

ProportionalACE

Frequency DeviationCPS1 MW Bias

IntegratedACEOR

PLC Regulation Logic


Slide 44


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.


Slide 45


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.


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)


Slide 48



Slide 49



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.


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


Slide 53

CPS1 Calculation

100*21 1212 monthmonth CFCPS

Good scores range from 100% to 200%


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.


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%


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


Slide 57

How Are We Doing With CPS1?


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


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


For FPL Control Area, L10 = 114.21 MW

Slide 61

FRCC 2006 CPS2 Bounds


Slide 62

CPS2 Calculation

1010 )( LACEAVG

Good scores range from 90% to 100%


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


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.


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




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.



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)


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.



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



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




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


Penalty FactorsUnits nearer to the load center: Units farther from the load center:

Penalty Factors are calculated by the Network Applications


$/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


$/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


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.


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



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



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



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


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!

http://pw.elec.kitami-it.ac.jp/ueda/java/ELD/

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



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.


Slide 96

Economic Dispatch



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!


Control Economic Dispatch

Slide 98


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.


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


Slide 100

Generation Requirement

Operator decisions impact generation

requirement; in this example, another unit is

added for regulation!


Slide 101


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.


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


Advisory Economic Dispatch

Slide 104


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.


Study Economic Dispatch

107

Questions?

Generation: Control & Economic Dispatch 2016 System Operator Seminar.

Documents

area generation

system speed frequency

system frequency change

primary control

communications generation

frequency transducer

scheduled frequency

speed change