Generation: Control & Economic Dispatch

Generation: Control & Economic Dispatch
2016 System Operator Seminar

What is Covered Automatic Generation Control Basics
ACE Equation Understanding FPL Generation Unit Status Display Unit Control Via AGC Control Performance Standards Economic Dispatch Basic Theory Control Economic Dispatch Study Economic Dispatch (using Economy A) Introduction

Automatic Generation Control Basics

Energy Balance Demand Generation AGC Basics Power Generated Imports
Losses Loads Exports Demand Generation Source: AGC Basics

Imbalance Conditions Over-generation Under-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

Control Responses Inertial Response Frequency Bias Characteristic
Governor & Load Response Regulation Control Economic Control System Operator Interconnected operation requires reasonable control of frequency and transmission network power flows Frequency control is assisted by an interconnection’s natural regulation. This regulation is provided by governor action and load sensitivity to frequency. Both are in such direction as to oppose and halt frequency changes. This perpetually ongoing natural regulation (a.k.a., primary frequency response) constantly restores a balance between total interconnection generation and total load plus losses. The repeatedly restored balance, however, is fleeting and seldom at scheduled frequency, and it is only momentarily that generation in any area exactly balances the area obligation. Consequently, primary control does not maintain a satisfactory match between the trends of area obligation and area generation. Matching the trends of obligation and generation within areas is the function of secondary (centrally directed) contro1. Source: AGC Basics

Inertial Response Inertia - resistance to change in rotational speed
When 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 apart Forces are present that oppose the change created by the change in load AGC Basics

Governor Response AGC Basics
What are governors? Speed governors vary prime mover output (torque) automatically for changes in system speed (frequency). The speed sensing device is usually a flyball assembly for mechanical-hydraulic governors and a frequency transducer for electro-hydraulic governors. The output of the speed sensor passes through signal conditioning and amplification (provided by a combination of mechanical-hydraulic elements, electronic circuits, and/or software) and operates a control mechanism to adjust the prime mover output (torque) until the system frequency change is arrested. The governor action arrests the drop in frequency, but does not return the frequency to the pre-upset value (approximately 60 Hz) on large interconnected systems. Returning the frequency to 60 Hz is the job of the AGC (Automatic Generation Control) system. The rate and magnitude of the governor response to a speed change can be tuned for the characteristics of the generator that the governor controls and the power system to which it is connected The definition of droop is the amount of speed (or frequency) change that is necessary to cause the main prime mover control mechanism to move from fully closed to fully open. In general, the percent movement of the main prime mover control mechanism can be calculated as the speed change (in percent) divided by the per unit droop. (Source: AGC Basics

Load Response to Frequency
Portion of system load that increases or decreases when frequency increases or decreases Measured in MW/0.1 Hz Approximately % load change for a 1% change in frequency System Load = 22,000 MW Example: Frequency Change = +/ 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

Frequency Bias Governor Response Characteristics Frequency Bias Load
AGC Basics

Regulation Control “Regulating units” are generating units that provide fine tuning which is necessary for effective system control Governors 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

Response Time Hierarchy for Unit Control
System Inertia seconds Frequency Bias Characteristic < 5 seconds (Governor & Load Response) Regulation > 30 seconds Economic Re-Dispatch > 5 minutes AGC Basics

Plant Control Using AGC
Automatic Generation Control Turbine-generator unit Power System Ties to Neighboring Systems Control Signal Electrical Output Turbine-generator unit Control Signal Electrical Output Measurement of Electrical Output Frequency Transducer Measurement of Electrical Output AGC receives data from the power system via SCADA at a specified rate, typically every four seconds. AGC dispatches the generating units by issuing control signals through SCADA to the generating units' Distributed Control Systems (DCSs) every AGC execution cycle, typically every four seconds. Tie-line flows, unit outputs, and system frequency are by nature oscillatory; they typically swing up and down within periods of several seconds. AGC does not attempt to regulate these short-term swings. The governors of the unit prime movers provide primary control action for short-term swings. AGC provides supplementary or secondary control action, which attempts to maintain the steady state values at specific levels. AGC observes economic constraints and can also observe security or energy constraints when economically dispatching the units under its control. Measurement of System Frequency Measurement of Tie Flow to Neighboring Systems Measurement of Tie Flow to Neighboring Systems AGC Basics

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) Area Native Load and Losses Interconnection Frequency Support Obligation Scheduled Interchange Demand = + + In an interconnected system “control areas” are vested with the responsibility of secondary control, i.e., to set scheduled interchange (biased by the area’s frequency sup port obligation) and to control generation so that the control area’s boundary flow will reasonably match the area’s biased interchange schedule. Thus, each control area must maneuver area generation to acceptably match its own obligation (demand) trend. Source: Area Control Error

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. Area Control Error (ACE) Change in obligation is constantly occurring because of changes in load and scheduled interchange (and somewhat to variation of frequency.) Obligation typically changes much faster than generation can be controlled, hence practical (secondary) generation control can only attempt to match the trend of obligation. The mismatch is measured by ACE, a fundamental signal for control area operation. Its variation is due to the arbitrary nature of changes in obligation and generation. Source: Mismatch = Generation - Demand = Area Control Error

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

FPL Area Control Error Calculation
FREQUENCY COMPONENT + INTERCHANGE COMPONENT Σ ACE + + TIE LINE TELEMETRY ERROR COMPONENT Area Control Error

Frequency Component of ACE
Area Control Error

Interchange Component of ACE
Area Control Error

Tie Line Telemetry Error Component of ACE
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 Other Area FPL ANI = 80 MW SNI = 80 MW ACE = 0 MW PAC = 100 MW G L G L Area Control Error

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 Other Area FPL ANI = 100 MW SNI = 100 MW ACE = 0 MW PAC = 80 MW G L G L Area Control Error

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

Area Control Error

AGC Major Functions Load Frequency Control: AGC matches power generation with system load while maintaining the desired frequency Economic 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

FPL Total Generation Calculation
Sum of Energy Purchases Total Generation for Units Belonging to the FPL Operating Area St. Lucie Units (Adjustment) Merchant Plants not Serving FPL Operating Area - Σ FPL Total Generation - Miscellaneous Generations FPL Total Generation

FPL Native Load Calculation
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. - Σ FPL Native Load FPL Native Load

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 FMPA CES Schedule: City of Key West LSF Schedule: FMPA Loss Schedule Schedule to account for transmission losses for FMPA network service ML Schedule: Merchant Load Schedule KWO Schedule: West Nassau Delivery Schedule FPL Native Load

FPL Native Load Calculation: Actual Data

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

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

Load Rate Calculation Load Rate Calculation

Top of the Hour Schedule Change
Current Time THSC Transaction Schedule Profile 10 Minutes Before Next Hour Boundary Next Hour Boundary 10 Minutes After Next Hour Boundary Time At 10 minutes past the hour begin calculating the difference in Scheduled Power between the values at 10 minutes before the next hour and ten minutes after the next hour. For example, at 8:10 compute the difference between the values at 8:50 and 9:10. When a Scheduled Power change occurs, repeat the calculation using the same time frame until XX:51. Between XX:51 and (XX+1):09 use the difference between the current time and (XX+1):10. Three possible cases are as follows: Between 10 minutes past the hour and 50 minutes past the hour, compute the difference between the values at 50 minutes past the hour and 10 minutes past the next hour. Between 51 minutes past the hour and the end of the hour, compute the difference between the values of the current time and 10 minutes past the next hour. Between the beginning of the hour and 10 minutes past the hour, compute the difference between the values of the current time and 10 minutes past the next hour. Display the value for the change in the field currently used for Bus Bar Sales, and change the title of the entry from BBS to THSC. Display the value calculated at the hour. Whenever the magnitude of the change is greater than or equal to 400 MW change the color of the displayed value THSC title from black to red. THSC - the difference in Scheduled Power between the values at 10 minutes before the next hour and ten minutes after the next hour. THSC

Top of the Hour Schedule Change
Current Time THSC Transaction Schedule Profile 10 Minutes Before Next Hour Boundary Next Hour Boundary 10 Minutes After Next Hour Boundary Time At 10 minutes past the hour begin calculating the difference in Scheduled Power between the values at 10 minutes before the next hour and ten minutes after the next hour. For example, at 8:10 compute the difference between the values at 8:50 and 9:10. When a Scheduled Power change occurs, repeat the calculation using the same time frame until XX:51. Between XX:51 and (XX+1):09 use the difference between the current time and (XX+1):10. Three possible cases are as follows: Between 10 minutes past the hour and 50 minutes past the hour, compute the difference between the values at 50 minutes past the hour and 10 minutes past the next hour. Between 51 minutes past the hour and the end of the hour, compute the difference between the values of the current time and 10 minutes past the next hour. Between the beginning of the hour and 10 minutes past the hour, compute the difference between the values of the current time and 10 minutes past the next hour. Display the value for the change in the field currently used for Bus Bar Sales, and change the title of the entry from BBS to THSC. Display the value calculated at the hour. Whenever the magnitude of the change is greater than or equal to 400 MW change the color of the displayed value THSC title from black to red. THSC - the difference in Scheduled Power between the current time and ten minutes after the next hour. THSC

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

Causes of Inadvertent Incorrect Transaction Schedules
Uncoordinated Schedules Between Entities Inaccurate Tie Line Metering Bad Control Deliberate “pushing” or “pulling” of energy Bad frequency control Inadvertent Payback

FPL’s Inadvertent Payback Philosophy
Follow NERC standards Limit payback to 20% of frequency bias Done unilaterally Keep it below +/- 150 MWhr Economic awareness One-sided inadvertent payback

Unit Control Via AGC

How Do We Control Using AGC?
Economic Dispatch Basepoint Component Unit Setpoint Operator Entry Unit Control Logic Basepoint Schedule There are 2 basic inputs for unit control; for units under AGC control A basepoint component and a regulation component makes up the 2 major control inputs for a unit Regulation Component ACE Unit Control Via AGC

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) We usually use either CE or MR basepoints. We will discuss CE basepoint later when we discuss Economic Dispatch Take note that Mandatory ramp does not care about ACE! Unit Control Via AGC

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

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 Hz The calculated MW bias is used in place of the ACE Integral term in calculation of the regulation action Unit Control Via AGC

Regulation Component Processing
Predicted ACE Next 2-Minutes Transaction Schedules Proportional ACE Integrated ACE PLC Regulation Logic Raw ACE Integrated ACE OR CPS1 MW Bias Frequency Deviation Unit Control Via AGC

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

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

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 ( 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

The RRI is used to determine gains for the raw and integral ACE, which provide, respectively, the proportional and integral components. RRI: The regulation region indicator. The following are possible states: DBAND: In deadband, Regulation component for the area is zero. REGUL: Normal gain, used on ACE and ACE Integral to determine control actions. ASSIST: Assist gain, used on ACE and ACE Integral to determine control actions. EMERGY: Emergency gain, used on ACE and ACE Integral to determine control actions. REGULI: ACE Integral component forces out of deadband region. ACE Integral component of regulation is nonzero. Unit Control Via AGC

Unit Control Via AGC

Control Performance Standards

CPS1 Review 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

12-Month Compliance Factor
In simple terms, CPS1 assigns each Control Area a “slice” of the responsibility for control of Interconnection frequency. The amount of responsibility is directly related to Control Area size. ACE is to a Control Area what frequency is to the Interconnection. Over-generation makes ACE go positive and frequency increase. A large negative ACE causes frequency to drop. “Noisy” ACE causes “noisy” frequency. CPS1 captures these relationships. Frequency error is deviation from scheduled frequency. Normally this is deviation from 60Hz. Scheduled frequency is different during a time correction, but for the purposes of this discussion, assume scheduled frequency is always 60 Hz. Source: ACE is in MW deltaF is in Hz Bi is in .1MW/Hz Mathematical relationships between frequency and interconnection ACEs show that ACE coincidence with frequency error is a measure of the non-randomness of ACE. That is, non-randomness of ACE can be measured by its coincidence with AF. (The “coincidence” of signal z with signal y, is AVG{z x y}.) Analyses also show that coincidence among ACEs are significant contributors to deltaF magnitudes (Source: Control Performance Standards

Good scores range from 100% to 200%
CPS1 Calculation Good scores range from 100% to 200% Refer to the equation. Any minute where the average frequency is exactly on schedule or Control Area ACE is zero, the quantity ((frequency error)*(ACE)) is zero. Therefore CPS1 = 100* (20). CPS1 is exactly 200% whenever frequency is on schedule or ACE is zero. For any one-minute average where ACE and frequency error are “out of phase”, CPS1 is greater than 200%. For example, if frequency is low, but ACE is positive (tending to correct frequency error), the Control Area gets extra CPS1 points. Conversely, if ACE is aggravating the frequency error, CPS1 will be less than 200%. CPS1 can even go negative Control Performance Standards

CPS1 Review Control areas are not penalized when ACE benefits system frequency Negative 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

CPS1 Review Region of below 60 Hz and positive ACE
Region of above 60 Hz and negative ACE Control Performance Standards

CPS1 Charts Control Performance Standards
The Epsilon 1 target initially set for each Interconnection was on the order of 1.6 times historic frequency noise. This is why “average” Control Areas have been scoring around 160% for CPS1. The “bell curves” to the right of the ACE charts show the distribution of the individual one-minute CPS1 for both Control Areas for the hour. If frequency followed a normal pattern, whereby it fluctuated ± a few millihz from 60 Hz, the CPS1 curves for Control Area 1 and 2 would look like the “bell curves” to the right of their ACE charts. Both curves would have the same average (about 160% CPS1), but Control Area 2’s curve would be “wider.” In other words, the larger ACE swings would sometimes help frequency back to 60 more than Control Area 1, but sometimes hurt frequency more than Control Area 1. Even though the average effect of Control Area 1 and 2 on the Interconnection is the same, Control Area 2 sometimes places a greater burden on the Interconnection, as demonstrated by the size of the “left hand tail” of the CPS1 curve. A very long left tail implies poor control of some type (in this case regulation). Now look at Control Area 3. It is a “generation only” Control Area that is selling 100 MW for the hour. The problem is that it is meeting this requirement by generating 200 MW for the first 30 minutes and 0 MW for the last half of the hour. Again, if frequency conditions are normal, half the time the Control Area will be helping frequency back towards 60 Hz and half the time the Control Area will be hurting frequency. This means the Control Area will get an “Interconnection average” CPS1 score of about 160% for the hour. The graph of its CPS1 for the hour will, however, have wider tails, much like Control Area 2. The underlying problem in this case is Imbalance, not Regulation. The ACE chart for Control Area 4 shows that a generator tripped offline during the hour. If the CPS1 one-minute averages are plotted, the curve will also have wider tails. If the unit that was lost was large, the curve will be “skewed” to the left even further. This is because the unit loss will pull frequency down while ACE is a large negative value. In each case above there was a deficiency in one of the energy-based IOS (sometimes called ancillary services). The “left tail” of the underlying CPS1 curve captured each situation. Control Performance Standards

How Are We Doing With CPS1?
Control Performance Standards

CPS2 Review CPS2 is a “safety valve” standard that was put in place when CPS was developed Concern 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 Since CPS1 allows areas to benefit from a large abs(ACE) when ACE x deltaF is negative, a second performance standard, CPS2, is applied to ten minute average ACE. This standard is derived from an interconnection objective: RMS{deltaF10} .LE. Epsilon10; where deltaFIO is the ten minute average of deltaF, and Epsilon 10 is a target bound for the 12 month RMS of ten minute interconnection frequency error. Control Performance Standards

CPS2 Review CPS2 is a measure of average ACE over all 10- minute periods in a month Under CPS2, ACE is limited to a “regulating road” The width of the “regulating road” proportional to the Control Area’s size CPS2 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

L10 Formula For FPL Control Area, L10 = 114.21 MW
Source: Epsilon10 is a constant derived from the targeted frequency bound. It is the targeted RMS of ten-minute average frequency error from schedule based on frequency performance over a given year. The bound, Epsilon10, is the same for every control area within an Interconnection. The multiplier 1.65 is the statistical conversion factor from a 68.3% confidence limit (1 standard deviation) to a 90% confidence limit. (source: For FPL Control Area, L10 = MW Control Performance Standards

FRCC 2006 CPS2 Bounds Control Performance Standards
Source: ftp:// Control Performance Standards

Good scores range from 90% to 100%
CPS2 Calculation Good scores range from 90% to 100% Control Performance Standards

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 violation The 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 There are 720 hours in a 30-day month (or 43,200 minutes) This translates to 4,320 ten-minute periods If you violate CPS2 every other hour, your will have 360 violations CPS2 = 1 – (360/4320) = 91.67% PASS!!! Control Performance Standards

Compliance Control Compliance Rating = PASS if CPS1  100% and CPS2  90% Control Compliance Rating = FAIL if CPS1 < 100% and CPS2 < 90% Control Performance Standards

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

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. Economic Dispatch

Projected Natural Gas Prices
*units in 2004 $ per thousand cubic feet Sources: Economic Dispatch

Projected Electric Capacity Additions
Source: *units in gigawatts Economic Dispatch

Projected Production Costs
The average electricity production cost in 2004 for nuclear energy was 1.68 cents per kilowatt-hour, for coal-fired plants 1.90 cents, for oil 5.39 cents, and for gas 5.87 cents. (Source: Electricity production costs are a function of the costs for fuel, operations and maintenance, and capital. In the reference case, fuel costs account for about two thirds of the generating costs for new natural-gas fired plants, less than one-third for new coal-fired units, and less than one-tenth for new nuclear power plants in For most fuels, delivered prices to electricity generators peak by 2006, fall in the middle years of the projections, and then increase steadily through As a yearly average, natural gas prices drop to $5.06 in 2016 and then rise to $6.26 per million Btu in 2030 (Figure 65). Similarly, petroleum prices decline to $6.39 in 2013 and then rise to $7.61 per million Btu in Coal prices remain relatively low, with highs of about $1.50 per million Btu at the beginning and end of the projection period and lows of about $1.40 in the middle years. Nuclear fuel costs, averaging $0.45 per million Btu in 2004, rise to $0.60 per million Btu in 2030 (Source: *units in 2004 $ per million Btu Economic Dispatch

Load and System Incremental Costs
Economic Dispatch

Economic Dispatch Algorithm
Turbine-generator unit P1 PR = received power P1, P2, P3 = net power output of each generator Turbine-generator unit P2 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. Turbine-generator unit P3 Economic Dispatch

Economic Dispatch Algorithm
For the 3 unit example, the economic dispatch problem is to... minimize F1 + F2 + F3 where 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

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

Generator Costs Input-Output (IO) Curve Production Cost 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

Input-Output Curve Input Power (Mbtu/hr) Output Power (MW) PMIN PMAX
Valve Points (Steam) 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 Power (Mbtu/hr) PMIN PMAX Source: Output Power (MW) Economic Dispatch

The Production Cost Curve
If we multiply, the IO Curve with a constant fuel cost in $/Mbtu, the result is the Production Cost in $/hr. Production Cost ($/hr) Pout = Output Power (MW) Source: Economic Dispatch

Pout = Output Power (MW)
The Heat Rate Curve 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. Heat Rate (Mbtu/MWhr) Prated Pout = Output Power (MW) Source: Economic Dispatch

Slope of the IO Curve Pin = Input Power (Mbtu/hr)
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. Run = Pout Pin = Input Power (Mbtu/hr) Rise = Pin Pout = Output Power (MW) Source: Economic Dispatch

Incremental Cost Curve
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! $/MWHR PMIN PMAX Output (MW) Economic Dispatch

Example: Turkey Point No. 1
Economic Dispatch

Effect of Penalty Factor
Turbine-generator unit P1 High Voltage Transmission System I2R LOSSES Turbine-generator unit P2 PLOAD Turbine-generator unit P3 Economic Dispatch

Penalty Factor 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. Economic Dispatch

Penalty Factors are calculated by the Network Applications
Units nearer to the load center: Units farther from the load center: Penalty Factors are calculated by the Network Applications Economic Dispatch

Penalty Factors NO PENALTY FACTORS
$/MWHR $/MWHR 200 MW 200 MW NO PENALTY FACTORS Two identical units with the same Incremental Cost Curve were dispatched at the same MW level. Economic Dispatch

Penalty Factors Curve shifted down! Curve shifted up!
Pf = 0.9 Pf = 1.1 $/MWHR $/MWHR 270 MW 130 MW 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. Economic Dispatch

Incremental Cost Curves
In 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. Economic Dispatch

F1(P)/P F2(P)/P F3(P)/P  P(MW) P(MW) P(MW) Determine power generation requirement, PR=500 MW; guess a starting Lambda Economic Dispatch

F1(P)/P F2(P)/P F3(P)/P  100 P(MW) 250 P(MW) 100 P(MW) 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). P2  P1 P3 PT= =450 Economic Dispatch

Adjust  up or down until
Solving the Economic Dispatch Problem F1(P)/P F2(P)/P F3(P)/P  100 P(MW) 250 P(MW) 100 P(MW) Adjust  up or down until P1 + P2 + P3 = PR P2 Adjust   P1 P3 Compare to PR Economic Dispatch

Iteration is stopped when PT = 500
Solving the Economic Dispatch Problem F1(P)/P F2(P)/P F3(P)/P  120 P(MW) 275 P(MW) 105 P(MW) Iteration is stopped when PT = 500 P2  P1 P3 PT= =500 Economic Dispatch

Live Example http://pw.elec.kitami-it.ac.jp/ueda/java/ELD/
For these examples... observe what happens when the units are at their limits! Economic Dispatch

Do we know what we are doing?
The purpose of Economic Dispatch is to minimize the production cost of on-line generation. For example, if we need to serve 300 MW... 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. Economic Dispatch

X If unit 1 was not committed at all, unit 2 fulfills the load requirement with a lower system production cost! Economic Dispatch

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

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 This is the generation value that we are trying to optimize Control Economic Dispatch

Generation Requirement
Operator decisions impact generation requirement; in this example, another unit is added for regulation! 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. The MW range available for each PLC's basepoint is constrained by its operator-entered limits, its current dynamic basepoint (or optionally its current actual generation), and its normal response rate (MSR). Control Economic Dispatch

Lambda The 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

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. AED (also known as System Economic Dispatch) provides advisory information regarding economical loading of all PLCs whose type is defined as dispatchable. AED is essentially the same as CED, except that it is run for all units that are not in the OFF status. It typically executes at a nominal rate (programmer/analyst-adjustable) of every 5-10 minutes. AED results provide the optimum desired basepoints for PLCs operating in BL, BP, EC, EX, or AV mode, or in MAN status. Comparing AED basepoints to the current output of the units controlled by these PLCs gives an idea of how close or how far from the economic optimum the units are actually operating. Advisory Economic Dispatch

Basepoint Adjustment Factor
The PLC BPA factor indicates the fraction of the area's load-following requirement that the PLC will carry. For AGC to correctly control the system, the sum of the effective basepoints in the system must match the current generation demand. A non-zero ACE value will be calculated when this is not the case. Normally, minute to minute adjustments to the Basepoint values are performed by the CED. Basepoint Adjustment performs the same function in systems that have inadequate economic dispatch range or no dispatchable units online. The Total Basepoint Adjustment (mismatch between the generation demand and sum of the current basepoints in the systems) is distributed to the available PLCs according to a new set of distribution factors. AGC's automatic basepoint adjustment function honors the load following generation requirements by distributing the requirement to each PLC under automatic control based on operator entered PLC BPA factors.

Study Economic Dispatch

Generation: Control & Economic Dispatch

Similar presentations

Presentation on theme: "Generation: Control & Economic Dispatch"— Presentation transcript:

Similar presentations

About project

Feedback

Log in

Auth with social network:

Generation: Control & Economic Dispatch

Similar presentations

Presentation on theme: "Generation: Control & Economic Dispatch"— Presentation transcript:

Similar presentations

About project

Feedback