1. Bob Green Garland Power and Light
Governor and AGC Control of System Frequency TRE Technical Workshop March 31, 2009
Bob Green
Garland Power and Light

2. Two generators equipped with governors having output feedback

3. Schematic of a governor with output feedback

4. Response of governor with output feedback

5. Steady-state speed characteristic (droop) curve

6. Calculation of steady-state speed characteristic
R(per unit), the slope of the “droop” curve, is defined as f(p.u.)/ P(p.u.), where f(p.u.)= f(HZ) / 60.0, and P(p.u.)= P(MW) / Unit Capacity. For a 600 MW unit that has a governor response of 20 MW for a frequency excursion that settles out at 59.9 HZ, R=f(p.u.) / P(p.u.) = (0.1/60)/(20/600) =0.05 or 5% droop. Once the droop is known, the MW response to frequency deviation can be determined by (P/f)=(1/R), or P=(1/R) X f. For the 600 MW unit with 5% droop, (P/600)=(1/0.05) X (f/60), or P=200MW/HZ

7. So, how do governors with the steady-state speed characteristic interact when there are multiple generators in a power system? What determines the steady state system frequency after a load is added to the system?

8. Multiple Generator Governor Response
Consider an isolated power system with three generators on-line and operating at 60HZ. The load is 360 MW and the generator outputs for units #1, #2 and #3 are 80MW, 120MW and 160MW, respectively.
A load of 21MW (P) is added. What frequency does the system settle at? How much does each unit pick-up (MW)?
Since R(p.u.)=( f(HZ)/60)/( P(MW)/Capacity),
then (P/f)=(1/R) X Capacity/60).
UNIT
CAPACITY
R (DROOP)
P/f #1
300MW
0.100 (10%)
50MW/HZ #2
450MW
0.075 (7.5%)
100MW/HZ #3
600MW
0.050 (5%)
200MW/HZ
Solution:
Unit #1: P1=50 X f
Unit #2: P2=100 X f
Unit #3: P3=200 X f
Pi=350f=21MW,
and f=21/350=0.06HZ
Frequency= =59.94HZ
P1=50 X 0.06=3MW
P2=100 X 0.06=6MW
P3=200 X 0.06=12MW
check: Pi=21MW

9. Three generators serving 360MW

10. Three generators serving 367MW

11. Three generators serving 374MW

12. Three generators serving 381MW

13. The system frequency reaches steady-state at a value that causes the sum of the on-line generator output MW to be equal to the system load MW. With this type of governor, when the system load increases, the system frequency decreases and visa versa. How do we control frequency to 60HZ, no matter what the load is?

14. Power system equipped for supplemental control

15. Addition of a speed changer

16. Steady-state speed characteristic with speed changer

17. Power output as a function of frequency

18. How does the addition of the speed changer to the governor facilitate the control of frequency? Hint: The system frequency reaches steady-state at a value that causes the sum of the on-line generator output MW to be equal to the system load MW.

19. From a central site, you increase or decrease the 60HZ set-points until the sum of the 60HZ set-points is equal to the system load. Then the frequency will stabilize at 60HZ. This form of supplemental control is called Automatic Generation Control (AGC) and more specifically, Load Frequency Control (LFC).

20. Load of 367MW and 60HZ SPs increased by 7 MW

21. Load as a function of frequency (load damping)

22. Governor and load characteristic curve intersection

24. Illustration of typical governor dead band

25. Generation oscillations at the dead band frequency

26. Primary Control
Secondary or Supplementary Control
Common Name
Governor Control/Response
AGC Control/Response
Function-Generic
Holds the system together as load changes occur and also as un-commanded generation excursions occur
Shifts generation between units to achieve security and economic objectives plus restores frequency to the rated value.
Function-Technical
Provides the correct amount of mechanical input to turbines to match the electrical output of the corresponding generators
Changes the 60HZ governor set-points of the units to achieve scheduled values established by the market.
Control Input
Frequency/rotational speed of the turbine
In ERCOT, the SCE for the portfolio of units
Control Time Constant
Fast - Seconds
Slower - Tens of seconds and minutes
Style of Control
Local within the Units/PGCs—A QSE has no direct control over governor response.
Centralized from ERCOT to Units via QSEs
Performance Optimization
Having more governors on-line (with a given droop characteristic) will minimize the magnitude of frequency deviations
Having more units being controlled by AGC will minimize the duration of frequency deviations
Key Parameters
Steady state speed characteristic (droop), governor dead-band, first stage boiler pressure (steam units) and head (hydro units)
Base power schedule plus deployments of balancing energy, regulation energy, responsive and non-spinning reserve. AGC dead-band, gains and frequency bias term.
Market Characteristics
If there ever is a governor response market, there will probably be bids, awards and settlement, but the market will never deploy the governor response.
Bids, awards, deployments and settlement through the Ancillary Service Market. Performance monitoring of individual Services is approximate and complicated.
Disturbance Timeline
Initial governor response (to point B) is over completely by the time units start receiving secondary control signals in response to the disturbance.
There needs to be recognition of governor response and coordination between RRS and RegUp deployments to insure smooth , rapid and sustained frequency recovery.