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

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

Calculation of steady-state speed characteristic

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

Σ∆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: Σ∆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.