1. Generation Constraints and Considerations
Phillip Jarreau
Cycle 5
2010

2. Objectives—Generation Constraints
Explain generation control and the impact performance has on the power system
Identify the difference between normal, permissive, and emergency regulating states
Describe typical problems that affect generators and actions that the system operator can take in response to these problems
Describe factors other than economic that determine the way generating units are dispatched

3. References General Physics NERC CBT NERC website NERC.COM
SPP System Operator Training Program Modules
Current Day Procedures

4. Generation Constraints & Considerations
Goals of AGC:
Maintain frequency at its nominal value.
Maintain compensated net interchange at the scheduled value.
Allocate generation economically among available units. Not, allocating generators equally
The AGC mode required by NERC
Tie line bias control

5. Generation Constraints & Considerations
Area Control Error (ACE) represents the mismatch between generation and load within a control area.
ACE should be maintained as close to zero as possible at all times.
Control performance is the expression used to describe how well the ACE is controlled.
The NERC Control Performance Standard has criteria for continuous monitoring and for disturbance conditions. There are two Control Performance Standards for continuous monitoring: CPS1 and CPS2.
Entergy has been operating under a NERC field trial program that uses BAAL in lieu of CPS2

6. Generation Control and Performance Standards
CPS1—12 month rolling avg.
Control Compliance Rating = Pass if CPS1 ≥ 100%. Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of the clock-minute averages of the Balancing Authority’s Area Control Error (ACE) divided by 10B (B is the clock-minute average of the Balancing Authority Area’s Frequency Bias) times the corresponding clock-minute averages of the Interconnection’s Frequency Error is less than a specific limit.
The CPS1 equation can be simplified as follows:
CPS1 (in percent) = 100* (2 – (a Constant 1)* (frequency error)*(ACE))
Frequency error is a deviation from scheduled frequency. Normally this is a 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.
Refer to the equation above. 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.

7. GMS CPS1 screen shot of our current levels

8. Generation Control and Performance Standards
Should the BAAL field trial be suspended or ended Entergy would have to comply with CPS2
CPS 2 is considered pass at 90 %
CPS2 relates to a bound on the ten-minute average of ACE.
CPS2 is measured for a monthly average
CPS2 is a measure of ACE over all 10-minute periods in a month. Under CPS2, ACE is limited to a “regulating road” whose width is proportional to a Control Area’s size.
The term used to describe the width of the road is L10 and for Entergy that number is currently

9. Generation Control and Performance Standards
So this means that L10 is a boundary around you ACE.
CPS2 (percent) = 100 * (periods without violations)/(all periods in the month)
Periods are 10minutes in length
CPS2 must be 90% or greater for month or Control Area is in violation.

10. CPS2 Trend Example

11. GMS 10 Min Average

12. CPS2 Daily Impact 6 ten min periods per hour times 24 hours per day
6x24= x .9= = 14.4
More than 14 hits per day would negatively impact your monthly average

13. GMS CPS2 Daily Data

14. CPS2 Daily Data Date Selection

15. CPS 2 Analyzer

16. CPS 2 Analyzer (Cont)

17. Generation Constraints & Considerations
The central concept of the NERC control performance standards is that when frequency is considered, a control area’s ACE can be either good or bad:
Good ACE drives frequency up when frequency is low
Bad ACE drives frequency down when frequency is low
Good ACE drives frequency down when frequency is high
Bad ACE drives frequency up when frequency is high
Mathematically stated good ACE is ACE that has the opposite sign to ΔF and bad ACE is ACE that has the same sign as ΔF.
ΔF is negative when frequency falls below 60 Hz and positive when frequency rises above 60 Hz.

18. Generation Constraints & Considerations
Unit Control Modes:
Automatic
Automatic mode follow load fluctuations with the incrementally lowest cost generation.
Regulating mode follow load fluctuations with available regulating generation, regardless of incremental cost.
Economic
Units in an economic control mode do not participate in regulation.
Manual
Units in manual control mode must be dispatched by the System Operator.

19. Goals of an AGC System Review from Generation Control Cycle Training
A control area’s AGC system is used to maintain a constant 60 Hz frequency and scheduled interchange
An additional duty of an AGC system is to assist in the economic utilization of the control area’s generating resources
The AGC system, then, has two major functional areas associated with maintaining frequency and scheduled interchange:
Regulation Function
Economic Dispatch

20. Economic Dispatch Function Review from Generation Control Cycle Training
The economic component is the movement needed to place the unit economically in the fleet.
For instance, if the regulation error is +20 and the economic error is +10 then the unit would be asked to pick up +30 MWs.
On the other hand, if the regulation error is + 20 and the economic error is -5 then the sum is +15 and will be pulsed to the unit.
The economic dispatch function adjusts the generators’ outputs using the most economic mix of generation on line. Unlike the regulation function, the economic function of the AGC compares the relative costs of the unit and determines which units are the most economic to meet the current change in system load (Base Points).
Economic dispatch is a “coarse” adjustment because of the economic runs CED (5 Mins)/AED (10 Mins), while load regulation is “fine tuning.”
THE ECONOMIC DISPATCH FUNCTION
The load regulation function is intended to be used only for minor changes in control area
generation, while the economic dispatch function is responsible for large changes in system’s
load, such as those required to meet the load increases from the morning to the peak load hour.
When major changes in generation are required, the regulation function could, in theory, be used
to adjust generation in the same manner as done for minor load changes. The problem is that the
load regulation function does not make the large adjustments in the most economic manner
possible. The economic dispatch function, on the other hand, adjusts the generators’ outputs
using the most economic mix of generation on line. Unlike the regulation function, the economic
function of the AGC compares the relative costs of the unit and determines which units are the
most economic to meet the current change in system load.
Once the economic dispatch function of an AGC system makes large adjustments in the MW
output of the generators to satisfy load requirements, load regulation then makes small
adjustments around the operating points chosen by economic dispatch. Economic dispatch is a “coarse” adjustment, while load regulation is “fine tuning.”
The AGC system’s role in generation control is important, but it is not without limitations. AGC
is used during normal daily operations. When large frequency excursions occur, those greater
than 0.2 to 0.3 Hz, many utilities will disable the AGC system and turn power system control
over to their system operators.

21. Regulation Function Review from Generation Control Cycle Training
Involves adjustments to the MW output of control area generators to compensate for the constantly changing load magnitude, which could include steel mills, QF and/or EWG, as reflected in ACE
An AGC system makes these generation adjustments every few seconds to compensate for normal, minor load changes
Within a control area only a portion of the generators on line are assigned a role in load regulation. Large base-loaded generators, such as nuclear units, are not typically used for load regulation
The regulation function adjusts the output of each generator on regulation control (AGC) by determining its participation within the regulating unit group (those on control), which is a ratio of each unit’s ramp rate to the total ramp of the fleet (Participation Factor)

22. Generation Constraints & Considerations
Factors affecting AGC control performance:
Poor unit response.
Steady or sudden changes in system load or QF put.
Sudden changes in interchange schedule
Unit testing.
Unit not responding and a “NT” on GMS Margin screen
NT means Not Tracking and indicated that AGC not responding due to saturation or unit is not responding by system not seeing a “H” or “L” indication.

23. Generation Constraints & Considerations
Regulating States indicates how much control action is being implemented by the AGC:
Three main states:
Normal (EES=Economic)
If ACE is < +-75, then = 1 X ACE (gain factor)
Permissive (EES=Assist)
If ACE is > and < , then = 2 x ACE (gain factor)
Emergency (EES=Emergency)
If ACE is > 150, then = 4 X ACE (gain factor)
+150
+75
+75
-150

24. Generation Constraints & Considerations
Regulating states (cont’)
In the normal state, units assigned to the economic control mode are moved automatically for economics
In the permissive state, only units which are moving in a direction to correct ACE are allowed to change their output
In the emergency state, all the regulating units are sent to either their maximum or minimum regulating limit to correct the ACE, after the demand out-strips the Participation Factor demand
Remember Gain Factor is the multiple for ACE calculation

25. Generation Constraints & Considerations
Three AGC components that affect the amount of regulation supplied by a unit on AGC:
Penalty factors
Regulation participation
Ramp rates
GFOT X Regulation State
1 (Economic) examples:
ACE 50 X 1 = 50
ACE 50 X .10 = 5
2 (Assist)
ACE 100 X 2 = 200
ACE 100 X .10 = 10
4 (Emergency)
ACE 200 X 4 = 800
ACE 200 X .10 = 20

26. Generation Constraints & Considerations
Penalty factors are a way of economically accounting for transmission losses when dispatching generation
State estimator is constantly calculating against the actual system configurations, lines in or out and load flow levels.
You would monitor the penalty factor runs on the Generation Summary display
Penalty factors affect regulation only when economics are included in regulation. If AGC simply dispatches units to regulate without regard for economics, penalty factors do not affect response.

27. Operating Constraints & Considerations
A regulation participation factor is the amount of regulation assigned to a unit by the System Operator as a part of the total amount of a control area’s regulation.
If a unit is assigned a RPF of .3, the unit is given 30% of the control area’s required regulation response to cover the ACE.
Regulation participation factors share regulation among units assigned to automatic control.
Regulation factors should sum to 1 or 100%.
Higher participation factors will receive more regulating pulses from AGC.

28. Operating Constraints & Considerations
The AGC program uses the ramp rate value as a factor in combination with the RPF when assigning regulation pulses.
When the AGC ramp rate value closely matches the actual value at the unit, the AGC regulation function is optimized.

29. Operating Constraints & Considerations
The current value of ACE and the ACE trend are two major indicators of a system’s control performance.
System Operator must check the CPS1 and CPS2 control performance indicators in GMS to evaluate the performance of the units that were assigned to regulate during the previous hour.
Significant number of violations may be due to a poor response by one or more of the regulating units.
Evaluate the causes for poor response and take action accordingly. It may be necessary to take a unit off of regulation and place a different unit on regulation.

30. Generation Constraints & Considerations
Checking the amount of inadvertent each hour allows the System Operator to determine how closely the system met its scheduled interchange.
ACE has both an interchange and frequency component. Even if the control area is meeting its net scheduled interchange, the regulating units may be moved to help with frequency control.
This results in good inadvertent since it contributes to relieving poor frequency control on the Interconnection.

31. Generation Constraints & Considerations
Fuel Problems (coal):
As coal sits in the elements, it gets wet and loses some of its ability to burn well.
After a large amount of rain at a generating plant, wet coal from the pile causes problems in the boiler.
Plugged feeders and pulverizers and uneven burning in the boiler make the generating unit less stable.
Unit derates are common, and the unit is not capable of changing load quickly.
Option: Schedule extra generation on-line to cover anticipated derates.

32. Generation Constraints & Considerations
When a mill or pulverizer is plugged due to foreign matter getting inside, the system operator can expect what?
The unit to trip offline
The unit to be manually taken out of service
A derate of 70 to 100 MW on the unit
Constant MVA output with a decrease in the MW component but an increase in the MVAR component.

33. Generation Constraints & Considerations
Fuel Problems (gas):
Problems arise when a system contracts to use a certain amount of gas during a one- month period, and that amount is used before the month period is over.
Options:
Switch the gas-fired units to oil if they are capable of firing on both fuels.
Seek reliable interchange power for the short term.

34. Generation Constraints & Considerations
Fuel Oversupply:
The condition of having too much fuel is usually the result of “take or pay” contracts which require that a certain amount of coal (or gas) be paid for whether the fuel is used or not.
Options:
The fuel cost for the excess is adjusted downward to reflect the savings the system gains by burning the fuel instead of simply paying for nothing. The lower fuel costs provide an incentive for other systems to purchase energy from the unit. The selling system loses less money by selling power at a lower fuel cost than paying and receiving no fuel. It is called “dumping” power on the system.
Entergy does not practice this!

35. Generation Constraints & Considerations
Change in availability:
Boiler feed pump is taken out of service on a unit using dual pumps, the unit is only capable of half-load output.
A mill or pulverizer is plugged due to foreign matter getting inside.
A generator turbine is out of balance and unable to obtain high loads without damaging vibrations.
When a unit is derated, the system operator should obtain the following information from the plant:
Whether repairs will be made while the unit is on-line or off-line.
The period of time the unit will be derated.
If the unit is capable of automatic control during the derate period.

36. Generation Constraints & Considerations
Loss of plant controller/computer
A plant controller (PLC “Programmable Logic Controller”) is a computer at a generating plant that receives signals from the AGC function of the EMS and assigns regulation to the individual units at the plant.
If a system operator receives an alarm that the PLC or unit RTU has been lost due to failure or communication problems, the units will need to be dispatched manually.
The total load calculation in a control area uses generating unit output as a component. If a bad signal from the generating plant or unit is used in the calculation, the total load is also wrong.

37. Generation Constraints & Considerations
Tie line telemetry failure
Tie line telemetry or metering is essential for calculating the ACE. ACE is the difference between net scheduled and net actual flows. The net actual flows are the flows in and out of a system over tie lines. If one of the tie line numbers is faulty due to a communication or RTU failure, the entire calculation is wrong.
If state estimated values are not available, the system operator will need to call the other system sharing the tie line for periodic updates on the instantaneous values. When the number is manually inserted into the EMS, the ACE calculation uses the approximate value to generate AGC pulses.

38. Generation Constraints & Considerations
Transmission System Reliability
Some problems on the transmission system:
MW flow overloads
voltage limit violations
Can be relieved in part or in whole by re-dispatching generation.
Power flows from generating units to loads via the transmission system. To avoid large flows on transmission lines, some generation must be raised or lowered adjust line loading. Running this generation is not the most economic choice, but is done for reliability.

39. Generation Constraints & Considerations
Transmission System Reliability (cont)
Some systems use generating units as the prime source of reactive power on the transmission system.
To alleviate the MVAR support problems, turbines in the local areas must be ran with increased MVAR output to boost voltage support.
The voltage on the system is determined by the settings of the automatic voltage regulators on the generators
At times, the turbines are brought on-line only to supply MVARs; little MW power is actually generated.

40. Generation Constraints & Considerations
Emissions Constraints
The Environmental Protection Agency (EPA) has designed measures to include emissions factors into dispatching power.
When pollution levels reach a pre-determined limit the EPA can declare a pollution alert. When this is done, the system operator may have to take action to reduce pollution output.
Reducing generating output on the affected units is an immediate measure, but load still exists on the system and must be covered. Some options for the system operator are to:
Purchase power from an unaffected system
Switch fuel in the unit to gas
Re-dispatch generation to unaffected units
Bring gas-fired combustion turbines on-line

41. Constraints & Considerations
NERC Standards
Current-Day Procedures

42. Generation Constraints & Considerations
Which ONE of the following may cause the System Operator to dispatch generating units in a non-economic manner?
Low load system conditions
Overvoltage conditions
Redispatch request
Inclement weather (hurricanes)
Transmission line overloads in an area of the power system
Request for economic transaction from neighboring utility

43. Review—Generation Constraints
Discussed generation control and the impact performance has on the power system
Identified the difference between normal, permissive, and emergency regulating states
Described typical problems that affect generators and actions that the system operator can take in response to these problems
Described factors other than economic that determine the way generating units are dispatched

44. Questions?