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

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 #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=60-0.06=59.94HZ P1=50 X 0.06=3MW P2=100 X 0.06=6MW P3=200 X 0.06=12MW check: Pi=21MW

Three generators serving 360MW

Three generators serving 367MW

Three generators serving 374MW

Three generators serving 381MW

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?

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 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.