Transcript Governor and AGC Control - Texas Reliability Entity

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
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=350f=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/PGCs—A QSE has no
direct control over governor response.
Having more governors on-line (with a given
droop characteristic) will minimize the
magnitude of frequency deviations
In ERCOT, the SCE for the portfolio of units
Slower - Tens of seconds and minutes
Centralized from ERCOT to Units via QSEs
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.
Common Name
Function-Generic
Performance
Optimization
Having more units being controlled by AGC
will minimize the duration of frequency
deviations