Governor and AGC Control - Electric Reliability Council of Texas
Governor and AGC Control of System Frequency TRE Technical Workshop March 31, 2009 Bob Green Garland Power and Light Two generators equipped with governors having output feedback
Schematic of a governor with output feedback Response of governor with output feedback Steady-state speed characteristic (droop) curve 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 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? 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
Unit #1: P1=50 X f P1=50 X 0.06=3MW Unit #2: P2=100 X f P2=100 X 0.06=6MW Unit #3: P3=200 X f P3=200 X 0.06=12MW Pi=350f=21MW, check: Pi=21MW and f=21/350=0.06HZ
Frequency=60-0.06=59.94HZ Three generators serving 360MW Three generators serving 367MW Three generators serving 374MW Three generators serving 381MW
The system frequency reaches steadystate 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?
Power system equipped for supplemental control Addition of a speed changer Steady-state speed characteristic with speed changer Power output as a function of frequency
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.
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).
Load of 367MW and 60HZ SPs increased by 7 MW Load as a function of frequency (load damping) Governor and load characteristic curve intersection Illustration of typical governor dead band
Generation oscillations at the dead band frequency Primary Control Governor Control/Response Holds the system together as load changes occur and also as un-commanded generation excursions occur Secondary or Supplementary Control
AGC Control/Response 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 Control Time Constant Style of Control
Frequency/rotational speed of the turbine Fast - Seconds Local within the Units/PGCsA QSE has no direct control over governor response. In ERCOT, the SCE for the portfolio of units Slower - Tens of seconds and minutes Centralized from ERCOT to Units via QSEs
Performance Optimization Having more governors on-line (with a given Having more units being controlled by AGC droop characteristic) will minimize the will minimize the duration of frequency magnitude of frequency deviations 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.
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