Frequency control (MW-Hz) with wind
Wind Generation Technology Short Course
October 27, 2010
Iowa State University
James D. McCalley
Harpole Professor of Electrical &
Computer Engineering
1
Outline
1.
2.
3.
4.
5.
6.
7.
MW-Hz time frames
Transient frequency control
Frequency governing
CPS1, CPS2
Simulations
Solutions
Conclusions
2
MW-Hz Time Frames
0+<t<2s; Inertial
t=0+; Proximity
2s<t<10s; Speed-governors
3
10s<t<5m; AGC
5m, ED
MW-Hz Time Frames
This is load decrease,
shown here as a gen
increase.
4
Source: FERC Office of Electric Reliability available at:
www.ferc.gov/EventCalendar/Files/20100923101022-Complete%20list%20of%20all%20slides.pdf
MW-Hz Time Frames
=
100
80
REGULATION IN MEGAWATTS
60
+
40
20
0
-20
-40
-60
-80
-100
07:00
07:20
07:40
08:00
08:20
08:40
09:00
09:20
09:40
10:00
Regulation
Load Following
Regulation
5
Source: Steve Enyeart, “Large Wind Integration Challenges for Operations / System
Reliability,” presentation by Bonneville Power Administration, Feb 12, 2008, available at
http://cialab.ee.washington.edu/nwess/2008/presentations/stephen.ppt.
Transient frequency control
What can happen if frequency dips too low?
• For f<59.75 Hz, underfrequency relays can trip load.
• For f<59 Hz, loss of life on turbine blades
• Violation of NERC criteria with penalties
• N-1: Frequency not below 59.6 Hz for >6 cycles
at load buses
• N-2: Frequency not below 59.0 Hz for >6 cycles
at load buses
6
Transient frequency control
Frequen
cy(Hz)
60
d f  PL f Re

 mf
n
dt
2 H i
t
1
mf1
60-mf1t1
60-mf2t1
i 1
Time
(sec)
mf2
mf3
60-mf3t1
The greater the rate of change of frequency (ROCOF) following
loss of a generator ∆PL, the lower will be the frequency dip.
ROCOF increases as total system inertia ΣHi decreases.
Therefore, frequency dip increases as ΣHi decreases.
7
Transient frequency control
Example: Ireland: ∆PL =432 MW=4.32 pu. ΣHi =475 sec
2.75 sec
Nadir
1. Governors
2. Load frequency sensitivity
49.35
mf 
 PL f Re
d f
 4.32(50)


 0.227 Hz / sec
n
dt
2 * 475
2 H i
i 1
50-0.227*2.75=49.38Hz
8
Transient frequency control
Example: Estrn Interconnection: ∆PL =2900 MW=29 pu. ΣHi =32286 sec
mf 
 PL f Re
d f

n
dt
2 H i
i 1

59.9828
Hz
 29(60)
 0.0269 Hz / sec
2 * 32286
60-0.0269*1.5=59.9597Hz
Nadir
59.9725z
9
Transient frequency control
So what is the issue with wind….?
1. Increasing wind penetrations tend to displace
(decommit) conventional generation.
2. DFIGs, without specialized control, do not contribute
inertia. This “lightens” the system d f  P f
L Re

 mf
(decreases denominator) 
n
dt
2 H i
i 1
Let’s see an example….
10
Transient frequency control
•
•
•
•
Green: Base Case
Dark Blue: 2% Wind Penetration
Light Blue: 4% Wind Penetration
Red: 8% Wind Penetration
Estrn Interconnection: Frequency dip after 2.9GW Gen drop for Unit DeCommitment scenario at different wind penetration levels (0.6, 2, 4, 8%)
11
Transient frequency control
Why do DFIGs not contribute inertia?
They do not decelerate in response to a frequency drop.
Fuel supply
control
Steam valve control
Generator
Steam
Boiler
FUEL
STEAMTURBINE
MVARvoltage
control
CONTROL
SYSTEM
Generator
Wind
speed
WINDTURBINE
Gear
Box
Real power
output control
MVARvoltage
control
CONTROL
SYSTEM
12
The ability to control mech
torque applied to the
generator using pitch
control & electromagnetic
torque using rotor current
control (to optimize Cp and
to avoid gusting) enables
avoidance of mismatch
between mechanical torque
and electromagnetic torque
and, therefore, also
avoidance of rotor
deceleration under network
frequency decline.
Transient frequency control
What is the fix for this? Consider DFIG control system
13
Source: J. Ekanayake, L. Holdsworth, and N. Jenkins, “Control of DFIG Wind Turbines,” Proc. Instl
Electr. Eng., Power Eng., vol. 17, no. 1, pp. 28-32, Feb 2003.
Transient frequency control
Add “inertial emulation,” a signal dω/dt scaled by 2H
-2H
dω / dt
14
Transient frequency control
Several European grid operators have imposed requirements on wind
plants in regards to inertial emulation, including Nordic countries [1,2].
North American interconnections have so far not imposed requirements
on wind farms in regards to frequency contributions, with the exception
of Hydro-Quebec.
The Hydro-Quebec requirement states [3, 4], “The frequency control
system must reduce large, short-term frequency deviations at least as
much as does the inertial response of a conventional generator whose
inertia (H) equals 3.5 sec.”
15
[1] “Wind Turbines Connected to Grids with Voltages above 100 kV – Technical Regulation for the Properties and
the Regulation of Wind Turbines, Elkraft System and Eltra Regulation, Draft version TF 3.2.5, Dec., 2004.
[2] “Nordic Grid Code 2007 (Nordic Collection of Rules), Nordel. Tech. Rep., Jan 2004, updated 2007.
[3] N. Ullah, T. Thiringer, and D. Karlsson, “Temporary Primary Frequency Control Support by Variable Speed
Wind Turbines – Potential and Applications,” IEEE Transactions on Power Systems, Vol. 23, No. 2, May 2008.
[4] “Technical Requirements for the Connection of Generation Facilities to the Hydro-Quebec Transmission
System: Supplementary Requirements for Wind Generation,” Hydro Quebec, Tech. Rp., May 2003, revised 2005.
β,
Frequency Governing Characteristic, β
“If Beta were to continue to decline, sudden frequency declines due to loss of
large units will bottom out at lower frequencies, and recoveries will take longer.”
Source: J. Ingleson and E. Allen, “Tracking the Eastern Interconnection Frequency
16
Governing Characteristic,” Proc. of the IEEE PES General Meeting, July 2010.
Reasons for decrease in β
• Fossil-steam plant changes, motivated to increasing economic
efficiency:
• Use of larger governor deadband settings, exceeding the historical typical setting
of ±36 millihertz (mHz);
• Use of steam turbine sliding pressure controls;
• Loading units to 100 percent of capacity leaving no “headroom” for response to
losses of generation;
• Blocked governor response (nuclear licensing may also cause this);
• Use of once-through boilers;
• Gas Turbine inverse response;
• Changes in the frequency response characteristics of the load:
• Less heavy manufacturing, therefore less induction motor load
• More speed drives which may reduce frequency sensitivity of induction motors
“These changes have been evolving for some time and are not the direct result
of the emergence of renewable resources such as wind and solar.”
Source: “Comments Of The North American Electric Reliability Corporation Following
September 23 Frequency Response Technical Conference,” Oct. 14, 2010. See
www.ferc.gov/EventCalendar/EventDetails.aspx?ID=5402&CalType=%20&CalendarI
17
D=116&Date=09/23/2010&View=Listview
Two Comments
1. Wind is small now, so the NERC comment that
decreasing β is not due to wind is correct,
but…this will not be true if, at higher wind
penetrations, non-wind units with speed
governing are displaced with wind units without
speed governing.
2. Decreasing β will risk violation of NERC Standard
BAL-001-0.1a — Real Power Balancing Control
Performance
Each Balancing Authority shall achieve, as a minimum,
• Requirement 1: CPS1 compliance of 100%
• Requirement 2: CPS2 compliance of 90%
and $ penalties apply for non-compliance.
So what are CPS1 and CPS2?
Ref: N. Jaleeli and L. Van Slyck, “NERC’s New Control Performance
Standards,” IEEE Transactions on Pwr Systems, Vol 14, No 3, Aug 1999.
CPS1 is a measure of a balancing area’s long term (12 month)
frequency performance. The targeted control objective underlying CPS1 is to
bound excursions of 1-minute average frequency error over 12 months in the
interconnection. As the interconnection frequency error is proportional to the
sum of all balancing areas’ ACEs, maintaining averages of ACEs within proper
statistical bounds will therefore maintain the corresponding averages of
frequency error within related bounds. With the interconnection frequency
control responsibilities being distributed among balancing areas, CPS1
measures control performance by comparing how well a balancing area’s ACE
performs in conjunction with the frequency error of the interconnection.
ACE  ( Ptie ,s  Ptie ,a ) | B | F
CP1min
CF 
ACE1min

 F1min
10 | B |
(CP1min )12Month
(1 ) 2
ε1 is maximum acceptable steady-state freq
deviation- 0.018Hz in east interconnection.
CPS1  (2  CF )  100%
19
CPS1
If ACE is positive, the control area will be increasing its
generation, and if ACE is negative, the control area will be
decreasing its generation. If ∆F is positive, then the overall
interconnection needs to decrease its generation, and if ∆F
is negative, then the overall interconnection needs to
increase its generation. Therefore if the sign of the product
ACE×∆F is positive, then the control area is hindering the
needed frequency correction, and if the sign of the product
ACE×∆F is negative, then the control area is contributing
to the needed frequency correction.
The minimum score of CPS1 compliance is 100%. If an
area has a compliance of 100%, they are supplying exactly
the amount of frequency support required. Anything above
100 is “helping” interconnection frequency whereas
anything below 100 is “hurting” interconnection frequency.
CPS2is a measure of a balancing area’s ACE over all
10-minute periods in a month. The control objective is to
bound unscheduled power flows between balancing areas.
It was put in place to address the concern that a balancing
area could grossly over- or under-generate (as long as it
was opposite the frequency error) and get very good CPS1,
yet impact its neighbors with excessive flows.
Num   ACE 10min  L10 
CPS2  100(1 
)% L10  1.6510 10 Bi 10 Bs 
Num  all  ACE 10min 
• Num(.) denotes “number of times that…” over 1 month.
• (ACE) 10min is the 10 min average of ACE
• L10 describes the interval within which |(ACE) 10min|
should be controlled.
• BS=sum of B values for all control areas.
• ε10 =targeted 10-minute average frequency error bound
for Interconnection
Simulation System
•Two Area System (Area A and Area B)
Wind power is assumed in area A
•Each area consists of 10 conventional units, with inertia and
with speed governing
• 24 hour UC is run based on a load and wind forecast
•Wind penetration levels- 6%, 10%, 25%, and 31% (Pw/Pnw) are
considered (by capacity), without inertia or speed governing
(would be 5, 9, 20, 24% Pw/(Pw+Pnw)).
• Wind is assumed to displace conventional units
• Actual sec-by-sec p.u. value of load and of wind power data
from one wind farm is used.
Con
Wind
A
B
Con
Simulation Results
180.00%
160.00%
140.00%
100.00%
CPS1 Score under different wind
penetration levels
80.00%
Minimum CPS1 score for CPS1
compliance
60.00%
40.00%
20.00%
0.00%
0%
6%
15%
25%
30%
Wind Penetration Level
120.00%
100.00%
80.00%
CPS2
CPS1
120.00%
CPS2 Score under different wind
penetration levels
60.00%
40.00%
Minimum CPS2 score for CPS1
compliance
20.00%
0.00%
0%
6%
15%
25%
Wind Penetration Level
30%
Simulation Results
Measures
0% wind penetration
CPS1
CPS2
160%
100%
Reference case at 25% wind penetration
78.80%
88.89%
Provide primary frequency control to wind turbines
98.84%
83.33%
Provide wind with inertial emulation & primary frequency control
109.58%
88.89%
Increase ramp rate of committed non-wind units by 50%
116.04%
94.44%
Increase ramp rate of committed non-wind units by 100%
156.02% 100.00%
Control fast variations of wind power within +- 2% of forecast
91.92%
88.89%
Control fast variations of wind power within +- 1% of forecast
124.64%
94.44%
Conclusion:
Wind degrades frequency performance due to
inertia, no control, and variability.
These 3 issues need to be and can be addressed.
Regulation via rotor speed & pitch control
Fuel supply
control
Generator
Steam
Boiler
FUEL
STEAMTURBINE
Pitch
control
Steam valve control
MVARvoltage
control
CONTROL
SYSTEM
Generator
Wind
speed
WINDTURBINE
Gear
Box
Real power
output control
MVARvoltage
control
Rotor
speed
25
control
Rotor speed control is well suited for continuous, fine, frequency regulation;
blade pitch control provides fast acting, coarse control both for frequency
regulation as well as emergency spinning reserve.
CONTROL
SYSTEM
Sources: Rogério G. de Almeida and J. A. Peças Lopes, “Participation of Doubly Fed Induction Wind Generators
in System Frequency Regulation,” IEEE Trans On Pwr Sys, Vol. 22, No. 3, Aug. 2007.
B. Fox, D. Flynn, L. Bryans, N. Jenkins, D. Milborrow, M. O’Malley, R. Watson, and O. Anaya-Lara, “Wind Power
Integration: Connection and system operational aspects,” Institution of engineering and technology, 2007.
Manufacturers & some wind farms have it
See http://www.gepower.com/prod_serv/products/wind_turbines/en/downloads/wind_plant_perf2.pdf.
Then why don’t they use it?
Regulation via rotor speed & pitch control
Review of the websites from TSOs (in Europe), reliability
councils (i.e., NERC and regional organizations) and ISOs (in
North America) suggest that there are no hard requirements
regarding use of primary frequency control in wind turbines.
There are soft requirements [1]:
•BCTC will specify “on a site by site basis,”
•Hydro Quebec requires that wind turbines be “designed so that they can be
equipped with a frequency control system (>10MW)”
•Manitoba Hydro “reserves the right for future wind generators”
NERC [2], said, “Interconnection procedures and standards should be
enhanced to address voltage and frequency ride-through, reactive and
real power control, frequency and inertial response and must be
applied in a consistent manner to all generation technologies.”
[1] “Wind Generation Interconnection Requirements,” Technical Workshop, November 7, 2007,
available at www.bctc.com/NR/rdonlyres/13465E96-E02C-47C2-B63427
F3BCC715D602/0/November7WindInterconnectionWorkshop.pdf.
[2] [North American Electric Reliability Corporation, “Special Report: Accommodating High Levels of
Variable Generation,” April 2009, available at http://www.nerc.com/files/IVGTF_Report_041609.pdf.
Regulation via rotor speed & pitch control
ERCOT says [1], “…as wind generation becomes a bigger
percentage of the on line generation, wind generation will have to
contribute to automatic frequency control. Wind generator control
systems can provide an automatic response to frequency that is
similar to governor response on steam turbine generators. The
following draft protocol/operating guide concept is proposed for all
new wind generators: All WGRs with signed interconnect
agreements dated after March 1, 2009 shall have an automatic
response to frequency deviations. …”
[15] Draft White Paper, “Wind Generation White Paper: Governor Response Requirement,” Feb,
2009, available at
www.ercot.com/content/meetings/ros/keydocs/2009/0331/WIND_GENERATION_GOVERNOR_RE
SPONSE_REQUIREMENT_draft.doc..
28
Solutions to degraded frequency performance
1. Increase control of the wind generation
a. Provide wind with inertial emulation & speed governing
b. Limit wind generation ramp rates
• Limit of increasing ramp is easy to do
• Limit of decreasing ramp is harder, but good
forecasting can warn of impending decrease and
plant can begin decreasing in advance
2. Increase non-wind MW ramping capability during periods of
expected high variability using one or more of the below:
a. Conventional generation  Steam turbine plants 1- 5 %/min
b. Load control
Nuclear plants 1- 5 %/min
c. Storage
GT Combined Cycle 5 -10 %/min
 Combustion turbines 20 %/min
 Diesel engines 40 %/min
29
12
Wind Speed (s)
Hybrid Wind Systems –
Save Money, Enhance
Frequency Regulation
10
8
6
4
2
0
200
400
600
400
800 1000 1200 1400 1600 1800
Time (s)
Wind Power
CAES Power
NaS Battery Power ×10
350
HUNTVILL
Power Command (MW)
300
NANTCOKE
HOLDEN
REDBRIDG
CHENAUX
CHFALLS
MARTDALE
BRIGHTON
STINSON
CEYLON
RICHVIEW
LAKEVIEW
PICTON
250
200
150
100
50
0
HEARN
-50
WALDEN
COBDEN
MTOWN
MITCHELL
HANOVER
0
200
400
600
KINCARD
60.04
800
1000
Time (s)
1200
JVILLE
STRATFRD
PARKHILL
DOUGLAS
System Frequency (Hz)
BVILLE
WVILLE
Wind Power Capacity
Compressor
CAES
Power Capacity
Gas Turbine
CAES Energy Capacity
NaS Battery Power Capacity
NaS Battery Energy Capacity
Cost ($M)
Investment Cost
Operation Cost
155.15
221.83
Life time: 20 years
60
25
96
6,110MW
10,995MW
1800
60.02
60.01
60
59.99
59.98
59.97
59.96
545MW
30MW
75MW
17,000MWh
5.5MW
1.25MWh
0
200
400
600
800
1000
Time (S)
1200
1400
1600
1800
100
With Storage
No Storage
80
Mismatch (MW)
Number of buses
Number of generators
Number of branches
Peak Load
Total Generation Capacity
1600
Wind plant
Hybrid Wind Systems
60.03
GOLDEN
1400
60
40
20
0
-20
-40
Saving ($M)
-60
481.40
-80
30
-100
0
200
400
600
800
1000
1200
1400
1600
1800
How to decide?
First, primary frequency control for over-frequency conditions,
which requires generation reduction, can be effectively handled by
pitching the blades and thus reducing the power output of the
machine. Although this action “spills” wind, it is effective in
providing the necessary frequency control.
Second, primary frequency control for under-frequency conditions
requires some “headroom” so that the wind turbine can increase
its power output. This means that it must be operating below its
maximum power production capability on a continuous basis. This
also implies a “spilling” of wind.
Question: Should we “spill” wind in order to provide frequency
control, in contrast to using all wind energy and relying on some 31
other means to provide the frequency control?
Answer: Need to compare system economics between increased
production costs from spilled wind, and increased production and
investment costs from using storage and conventional generation.
Conclusion: Select solution portfolio
Wind
Grid
energy prblem
attrbute caused
by wind
attrbute
Solutions
DFIG Control
Inrtial
emulation
Inc.
reserves
Freq
Fast
Spnng 1 hour
reg via rmping /10 min
pitch+
cnvrtr
Storage
Fast
Slow
Load Cntrl
Fast
Slow
Stochastic
Unit
Cmmt
prgrm
Dec
forecast
error
Wind
HVDC
plant
control
remote
trip
(SPS)
Geodiversity
of wind
Estimated relative costs/MW of solution technology (to be refined)
5
Decreased Transient
inertia
frequency
dips, CPS2
perfrmance
Increased
1 min MW
variability
Increased
10 min
MW
variability
Increased
1 hr MW
variability
CPS2
perfrmance
Balancing
market
perfrmance
Increased
day-ahead
MW
variability
Increased
transmissi
on loading
Day-ahead
market
perfrmance
Low,
variable
capacity
factor
CPS1,
CPS2
perfrmance
Increased
need for
transmssio
n
More
planning
uncertainty
5
6
10
10
√
√
√
√
√
√
9
9
9
9
4
4
6
10
10
√
√
√
√
√
√
√
√
√
√
√
√
√
√
√ √
√
√
√
√
√
√ √
√
√
√
√
√
√
32
√
√
√
√