I. Introduction
Power System Control and Operation
In actual power system, the active power (P) and the reactive power (Q) demand varies continuously. Steam input to generators must be regulated continuously to meet the active power (P) demand, so that the frequency can be kept constant. ( P-f control) e e exc a on e o e genera or s controlled to match the reactive power (Q) demand . control) ower s stem are ke t in normal Nowada s operating state by means of continuous, automatic closed-loop control.
Topic: Frequency Control and AGC . . Tel: 27666165 Email:
[email protected] Room CF610, EE Department, PolyU (ftp://www.ee.polyu.edu.hk/cychung/ee505/fre quency_control.pdf) (Reference Book: “Power System Stability and Control” by Prabha Kundur, McGraw Hill Inc., 1993) 1
Contr on tr ol o f a Generator enerator
2
Turbine Speed Governing System
turbine governor system potential transformer
+
T U P
Vref +
U O
excitation syss em sy
Efd
E pss
power system stabilizer
f spec spec voltage V t reactive power Q e
frequency f rotor speed
3
4
By considering a small deviation and with higher-order terms neglected, P0 P ( 0 )(T 0 T ) P 0 T T 0
Pm Pe 0 (T m T e ) (T m0 Since, in the steady state, T T
Power system loads are a composite of different electrical devices. For resistive loads, such as lighting and heating loads, the electrical power is independent of frequency. However, in the case of motor loads, , with frequency due to changes in motor speed.
T e 0 )
With speed expressed in pu, 0 1
Pm Pe T m T e P P Ms
Therefore,
+
P
The frequency-dependent load change can be denoted by: L ( freq )
1
+
ncorpora ng s n o diagram, we get:-
L
–
Ms
–
PL
Frequency sens ve oa change
e prev ous
1
From the block dia ram:
m
Ms
M s ( Ms D ) (Pm
oc
1
1
m
–
Non-frequency sens ve oa change
–
y
10
Pe P L D
+
v e
9
Thus chan es in electrical load have 2 com onent:-
Pm
w ere s e percen c ange n oa percent change on frequency
–
Pe
+
m
1
(Pm
L
P L ) P L )
1 MsD
– 11
PL
12
A small system consists of 4 identical 500MVA
H
5 .0 (
1020MW. The inertia constant H of each unit . . 1.5% for a 1% change in frequency. When there is a sudden dro in load b 20MW. (a) Determine the system block diagram with constant H and D ex ressed on 2000MVA base. b Find the fre uenc deviation, assumin that there is no speed-governing action.
M
2 H
500
) 4
5 .0
10 . 0
Expressing D for the remaining load (1020-20 =1000MW) on 2000MVA
D 1.5
1000 2000
0.75
The equivalent block diagram is:-
Pm
+
10 s 0.75
–
PL
13
.
P then
s
0.01 s
and
s
P 0
0.01
14
. An isochronous governor adjusts the turbine value/gate to bring the frequency back to the nominal or scheduled value.
for a sudden chan e
Generator
Valve/gate
1
Steam or water
s 10s 0.75 and taking inverse Laplace transform,
Y
(t ) (0.01/0.75)e-(0.75/10) t (0.01 / 0.75) -0.075 t . . the final value 0.0133 (at t infinity)
Integrator K
and a increase of 0.667 Hz for a 50 Hz system (e.g. HK) 0.8Hz for a 60Hz system (e.g. USA) 15
r
+
r
–
Load P ref
The measured rotor speed (r) is compared with the reference speed (ref ) . The error signal (speed deviation) is amplified and , steam supply valves. Because of the reset action of this integral controller, w reac a new stea y state on y w en t e spee error r s zero.
16
Response of generating unit with isochronous governor
-
r
ref
The isochronous governors cannot be used when there are two or more units connected to the same system since each generator would have to have precisely the same speed setting. Otherwise, they would fight each other, each trying to control s stem fre uenc to its own settin . For stable load division between two or more units operating in parallel, the governors are provided with a characteristic so that the s eed dro s as the load is increased.
Time
m
m
L
Pm 0
Time
An isochronous governor works satisfactorily when a generator is supplying an isolated load or when only one generator in a multigenerator system is required to respond to changes in load. For power load sharing between generators connected to the , provided. 17
Block diagram of a speed governor with droop
r
1
–
Steam Y or water
Integrator
K
–
+ –
To generator r
r
–
ref
R
18
Percent speed regulation or droop The value of R (droop) determines the steady-state speed versus load characteristic of the generating unit.
Y
r
s
–
Shaft
Turbine
value/gate position ( Y) or power output ( P) is equal to R . It can be expressed in percent as percent spee or requency c ange 100 R percent power output change
R
T
1
f NL
f FL f 0
100
f NL
f
f f f 0 f
0
+
ref
–
r
1
1
R
1 s T G
For example, a 5% droop or regulation means that a 5% frequency deviation causes 100% change in value position .
Y 19
f FL
100 Percent power output
20
Frequency( Hz )
. Curve 3 : Actual characteristic for hydraulic units
-
Generator can be driven by steam turbine or hydro-turbine. Here non-reheat turbine is considered. For non-reheat turbine, the block diagram is:-
Curve 2 : Actual characteristic for steam units
Pvalve
Percent power output 100
Steam turbines have a number of control valves, each having nonlinear flow area versus position characteristic. ac sec on o e curve represen s o e e ec o one control valve. , , have the characteristic similar to curve 3.
Pvalve = per unit change in valve position TCH
1
by the generator model above.
1 s TG
+
Pmech
Load reference set point
Pvalve 1 s TCH
PL (s)
and load
Prime mover
1
26
ep c ange o a s ng e genera or
R Governor
rom nomina = “Charging time” time constant
25
Combing the governor, prime mover, generator and load model, we obtain:-
–
Pmech
1 s TCH
+
s The transfer function for PL to is :-
1 MsD
–
L
PL
PL s
Equivalent block diagram for a single generator 27
1
1 R 1 s T 1
1 MsD 1 1 1 s T M s D 28
For several enerators connectin in arallel
s can e e s ea y-s a e va ue o found by: stea y state m s s
Pmech1
+
Pmech2
s 0
...
PL
D PL D 1 R D R
1
+ +
M eq s D
–
Pmechn
PL
Where D is a composite load damping constant and Meq is the inertia constant of the e uivalent enerator. The steady-state frequency deviation following a step increase in load is given by
Note: If D=0, the change of speed is:-
= -R PL
29
PL 1
1
R 1
R 2
......
1 R n
PL 1 R eq
30
The stiffness of the system (the composite frequency response characteristic and normally expressed in MW/Hz) is
PL 1 D R eq
A power system has a total load of 1,260MW at . . frequency (D=1.5). Find the steady-state frequency deviates when a 60MW load is suddenl tri ed if (a) There is no speed control. b The s stem has 240MW of s innin reserve evenly spread among 500MW of generation capacity with 5% regulation based on this capacity. All other generators are operating with valves wide open. Assume that the effect of governor dead bands is
The composite regulating characteristic of the system is equal to . The effort of governor speed droop and the frequency sensitivity of load frequency change can be P L PG
f 0
An increase of system load
P D
f
P D G
f
R
D
increase due to governor action and a total s stem load reduction due to its frequency-sensitive c arac er s c.
reduction in system load. 31
32
Total Spinning generation capacity = Load + Reserve = 1260 + 240 = 1500MW Generation contributing to regulation = 0.8 1500 = 1200MW A regulation of 5% means that a 5% change in frequency causes a 100% change in power generation. Therefore 1 5 1200 / 60 400MW/Hz R 100 The composite system frequency response characteristic
-
D
1.5 100
1200
/
1 60 100
30MW/Hz
,
-
increase,
f
L
D
30MW/Hz
2.0Hz
(b) Since there is a reduction in system load and an increase in frequency, all generating units (not just ose on sp nn ng reserve respon . owever, ue o the effects of dead band, only 80% of the total .
1
D 400 30 430MW/Hz R Steady-state increase in frequency
P
33
60
MW
430MW/Hz
e- ne
z 34
Two area system .
.
Electrical equivalent
o e
12
P12
Interconnection between power plant is common. Tie-line is the transmission line that connects two power plant together.
rea
E11 Area 2
X1
Xtie
Xtie
X
E22
XT=X1+Xtie+X2
The power flow on the tieline from area 1 to area 2 is
The most sim lest case is two areas each having a single generator and connected by a sin le transmission line. Power will flow from one area to another, and the direction of flow
1 2 sin( 1 2 ) X T Linearizin about an initial o eratin oint re resented by 1 = 10 and 2 = 20, we have T Pt e P T s E E 1 2 where T cos( )
Ptie
areas.
P12
10
35
T
20
36
1
tie
L
R
–
Prime mover
Governor
Pmech1
1
+
M sD
+
PL1
1 +
–
–
previous block diagram:
Ptie
Assume a load change of PL1 in area 1, w e L2 =
s
Load reference L2
+ Prime mover
Governor
–
–
+
– 2 1 2 s
+ Pmech2
s ea y-s a e, e requency w e constant and same for both areas. 1 = 2 =
2
1 R 2
mech1 -
37
L1 1 Pmech2 + Ptie = D2
+
tie
Pmech1
(2)
an re-arrang ng, we o a n:-
(3)
PL1 1 R 1
1
mech2
38
1 R 2
D1 D 2
PL1 1 2
Then substitute into (6), we get:-
R 2
PL1 D 2 R 2 PL1 2 Pt e 1 1 1 2 D1 D 2
(1) (3), we have : -
Ptie PL1 D1 (5) R 1 1 (2) (4), we have : Ptie D 2 (6) R 39
R 1
8
R 2
Equations (1) to (8) are for new steady-state conditions after load chan e. 40
An increase in area 1 load by PL1 results in a frequency reduction in both areas and a tieline flow of P . A negative P is indicative of flow from area 2 to area 1.
Frequency error for step change in load Load
PL1
Similarly, for a change in area 2 load by PL2, we
1 1
L2
1
D1 D 2
L2
1 2
Frequency error
1
1
R 1
R 2
1
2
me Response with no governor action
(9)
–
2
1 P D R 1 Ptie P12 P21
Step load change
P L2 1 (10) 1 2 41
Frequency error + –
PL1 D2
D1
Response with governor action
PL1 1 R 1
1 R 2
1
2
•
Objectives of Automatic Generation
•
1. To regulate system frequency to the spec e nom na va ve e.g. z. 2. To maintain the interchange power between control areas at the scheduled values. 3. To ensure each generator unit at the most economic value.
With primary speed control action, a change in system load will result in a steady-state frequency deviation, epen ng on e governor roop c arac er s c an frequency sensitivity of load. • All eneratin units on s eed overnin will contribute to the overall change in generation, irrespective of the location of the load change. requires supplementary control action which adjusts the load reference setpoint (through the speed-changer Therefore, the basic means of controlling prime-mover power to match variations in system load in a desired manner is t roug contro o t e oa re erence setpoints of selected generating units. • As s stem load is continuall chan in it is necessar to change the output of generators automatically.
43
42
44
Block Diagram of interconnected areas with
Fre uenc bias tie line control • A control signal made up of tieline flow deviation added to fre uenc deviation wei hted b a bias factor would accomplish the desired objectives (1) and (2).
ACE 1
P12 B1 f
B1 1
R1
D1
ACE 2 B2
Governor
+ACE
R2
1
+
D2
– ACE
2
+
• The Area Control Error (ACE) represents the required , . unit normally used for expressing the frequency bias factor B is MW/0.1Hz.
1
–
B1
P21 B2 f
2
1
1
K 1
+
P
s
s
+
•
P12 B1f 0 2 21 2 12
ACE 1
–
1
T s
+ Pmech2
+
– 2 1 M 2 s D2
46
From dynamic performance considerations, . For example, a sudden increase in load will resu t n a ecrease n system requency, followed by governor response which limits e max mum requency excurs on an subsequently (typically on the order of 10s) r ngs e requency ev a on ac o a value, which determined by the regulation c arac er s cs o o sys ems:
47
1
1 +
R 2
•
deviation and frequency deviation will result in stead -state restoration of the tie flow and frequency since the integral control action ensures that ACE is reduced to zero.
te
–
45
From steady-state performance considerations, . • Any combination of the area control errors
–
1
–
K Prime mover
1
+
AGC on selected units
2
•
Pmech1
Prime
PL1 1 2
48
IV. Implementation of AGC
(b) (v) Tripping of the tieline, with interchange schedule switched to zero
•
With interchange schedule switched to zero, area 1 supplementary control will pick up 1,000MW generation .
The control actions are determined for each control area at a central location called the dispatch centre. , telemetered to the central location. Control actions are determined by digital computer and transmitted through the same telemetry channels to the generators.
•
m ar y, area supp emen ary con ro re uces generation by 1,000MW to compensate for loss of . respective loads and the area frequencies are equal to 60Hz.
61
62
(iii) Control performance criteria (example) •
•
•
•
Much of the change in ACE is usually due to fast random variations in load to which eneratin units need not respond. Control action in response to these random componen s mere y causes unnecessary wear an tear on governor motors and turbine valves. , (SACE) is used to control generation.
• •
In establishing AGC signals, it should be recognized unit outputs can be changed. 63
Under normal conditions, the following criteria apply: 1) The ACE must return to zero within 10 minutes of . 2) The average ACE for each of the six 10-minute eriods durin the hour must be within s ecific limits. L d = 5 + 0.025L MW where L is the greatest hourly change in the net sys em oa o a con ro area on e ay o s maximum summer or winter peak load). , apply: (sudden loss of generation/increase of load; sampled ACE > 3L d ) 1) The ACE must return to zero within 10 minutes following the start of the disturbance. 2 T e ACE must start to return to zero wit in 1 64 minute following the start of the disturbance.
(ix) Effect of speed-governor dead band •
•
The dead band is defined as “the total magnitude of the change in steady-state speed within which there r u ur the governor-controlled valves or gates. rather than a line.
•
•
Dead band
•
• Valve/gate position 100%
The effect of the dead band on the speed governor response depends on the magnitude o e requency ev a on. If the deviation is small, it may remain en re y w n e ea an e spee control will be inactive. e pos on o eac governor wou e randomly distributed within its dead band. ence, or sma c anges n npu s gna , e response of the individual generating units . Speed governor dead bands result in random .
69
70
V. Underfrequency Load Shedding • • •
•
•
Disturbances can result in cascading outages and isolation of areas causin formation of electrical islands. An islanded area is undergenerated frequency decline Unless sufficient generation with ability to rapidly increase output is available, the decline in frequency will be largely determined by frequency sensitive . Frequency decline may reach levels that could lead to tripping of steam turbine generating units by underfrequency protective relays, thus aggravating the situation further. oa -s e ng sc emes are emp oye o re uce e connected load to a level that can be safely supplied by available eneration.
•
The vibratory stress on the long low-pressure turbine blades: Operation of steam turbine below certain frequency (such as 58.5Hz) is severely restricted.
•
The performance of plant auxiliaries driven by Hz), the plant capability may be severely reduced or fans supplying combustion air. (Nuclear power plants: The reactors may be overheat due to reduced flow of coolant). Generator may be tripped off by underfrequency relay to guard against this condition.
71
72
Limitations of prime mover systems to control frequency decay • •
•
•
The generation can be increased only to the limits of available spinning reserve within each affected area. The load picked up by a generator is limited due to erma s ress n e ur ne. o ur ne ra e output initially and then with slow increase of about . Limited ability of a boiler to pick up a significant amount of load. An increase in steam flow when the turbine values open pressure drop. An increase in fuel input to the boiler is required to restore pressure (takes several minutes)) The speed governors have a time delay of 3 to 5 secon s.
The following expression for frequency decay
f L(1 - e - ) K where K 1/ D and T M / D With D 1.0 and M 10s : f L(1 - e - t
73
• • •
74
Fre uenc trend rela
FTR
• A scheme based on frequency drop alone is generally acceptable for generation deficiencies up to 25%. • For greater deficiencies, both frequency drop and rate of change of frequency should be considered to provide increased selectivity by preventing unnecessary tripping of load in the system. • se s sc eme o r p appropr a e amoun s o oa n an area (maintain its integrity).
Maximum generation deficiency n mum perm ss e requency Range of inertia constant oa - amp ng cons an
yp ca sc eme or s e
) 60 Hz
Frequency decay for four values of overload L
• • • •
) pu L(1 - e - t
ng oa
10% load is shed when frequency drops to 59.2Hz 15% additional load is shed when frequency drops to 58.8 Hz 20% additional load is shed when frequency reaches 58.0 Hz 75
76
AGC configuration in a deregulated environment
Arrangement: – Gencos send the bid regulating reserves. – Bids are sorted by a prespecified time period and price. – Sorted regulating reserves with the demanded load from Discos, tie-line data from Transco, and the area requency to prov e contro comman s to trac t e area load changes. – s are c ec e an resor e accor ng o e received congestion information (from Transco) and
81
Gencos). – Control si nal transmitted to the Gencos once ever one to few seconds, while the results of computing participation factors and load generation scheduling by t e mar et operator are execute ai y or every ew hours.
82
AGC participants in a deregulated environment
• Market objective while encourage Gencos to provide sufficient regulation ower. Gencos: maximize their profits as allocations are made. 83
A synchronous area in AGC frameworks 84
An u dated AGC model • Area Control Error
ACE Ptie B f
•
Hi h enetration of wind ower reater amount of power reserve. • Solution: Using demand side control and intelligent power price management through intelligent meters and communications. • Solution: Battery Energy Storage Systems; Electric Vehicle. • ons era on o n s an u ma e so u on i) Advanced forecasting techniques ii RES wit mo ern automatic response contro to frequency
• Two new signals, representing the dynamic impacts of RESs on ' Local load: P L P RES P L Tieline power change:
Ptie' Ptie C Ptie RES
tie C , act
tie C , sc e
tie RES , act
tie RES , sc e
where Ptie C ,act , Ptie C , sched , Ptie RES ,act , Ptie RES , sched are actual conventional tieline power, scheduled conventional tieline power, actual RES tie-line power . 89
90
-
Conventional generation: 567.5 MW total PV unit: 2MW Wind farm: 30MW total
Wind velocity and output power of RES units 91
92
Dashed line shows response with PV unit only
(a) Frequency deviation following a 0.05pu step load disturbance 93
(b) A zoomed view around 50s
94
