1. 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

2. Outline MW-Hz time frames Transient frequency control
Frequency governing
CPS1, CPS2
Simulations
Solutions
Conclusions

3. MW-Hz Time Frames 0+<t<2s; Inertial
2s<t<10s; Speed-governors
10s<t<5m; AGC
t=0+; Proximity
5m, ED

4. MW-Hz Time Frames
This is load decrease, shown here as a gen increase.
Source: FERC Office of Electric Reliability available at:

5. MW-Hz Time Frames = +
Load Following
Regulation
Source: Steve Enyeart, “Large Wind Integration Challenges for Operations / System Reliability,” presentation by Bonneville Power Administration, Feb 12, 2008, available at

6. 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

7. Transient frequency control
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.

8. Transient frequency control
Example: Ireland: ∆PL =432 MW=4.32 pu. ΣHi =475 sec
49.35
Nadir
2.75 sec
1. Governors
2. Load frequency sensitivity
*2.75=49.38Hz

9. Transient frequency control
Example: Estrn Interconnection: ∆PL =2900 MW=29 pu. ΣHi =32286 sec
Nadir Hz z
*1.5= Hz

10. Transient frequency control
So what is the issue with wind….?
Increasing wind penetrations tend to displace (decommit) conventional generation.
DFIGs, without specialized control, do not contribute inertia. This “lightens” the system
(decreases denominator) 
Let’s see an example….

11. 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 De-Commitment scenario at different wind penetration levels (0.6, 2, 4, 8%)

12. Transient frequency control
Why do DFIGs not contribute inertia?
They do not decelerate in response to a frequency drop.
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.
FUEL
Steam Boiler
Generator
CONTROL SYSTEM
Steam valve control
Fuel supply control
MVAR-voltage control
Wind speed
Gear Box
Real power output control
STEAM-TURBINE
WIND-TURBINE

13. Transient frequency control
What is the fix for this? Consider DFIG control system
Source: J. Ekanayake, L. Holdsworth, and N. Jenkins, “Control of DFIG Wind Turbines,” Proc. Instl Electr. Eng., Power Eng., vol. 17, no. 1, pp , Feb 2003.

14. Transient frequency control
Add “inertial emulation,” a signal dω/dt scaled by 2H
-2H
dω / dt

15. 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.”
[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.

16. Frequency Governing Characteristic, ββ,
“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 Governing Characteristic,” Proc. of the IEEE PES General Meeting, July 2010.

17. 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
Basic idea of sliding pressure is that constant pressure requires throttling at lower loading levels and is therefore inefficient. The throttling can be eliminated
by sliding pressure controls, but this means if the pressure is low but the unit is required to increase, then it must wait for the pressure increase, which takes longer.
See
Constant pressure implies stable pressure of the steam generator and main steam line over the unit's load range. Meanwhile, the basic nature of a simple, rotating turbine is to require less pressure as load and flow rate are reduced, and if the main steam pressure is limited to only that required for each load, this mode is referred to as pure sliding pressure.
However, when we speak generally of "sliding pressure," we often mean modified sliding pressure, as shown in Figure 1. This mode has a limited amount of pressure throttling to provide a modest amount of fast-response load reserve. A unit under constant pressure will have significant load reserve at any reduced load, due to its significant pressure throttling or the availability of admission valve(s). By opening the throttle valve or an admission valve, the pressure in the turbine and steam generator move toward equalization. The sudden reduction of pressure in the steam generator prompts an instantaneous expulsion of steam mass due to the increase in a specific volume of steam within the confines of the system, and it provides a temporary load increase even before the fuel-handling and -firing system can be loaded to support any sustained higher load.
Once-through boilers (see
For supercritical plants, the accuracy and resolution of the DCS (distributed control system) is more important than in subcritical units. A well-designed control system that provides tight regulation and the ability to hit and maintain setpoints can help utilities capitalize on the economic and environmental potential these units offer.
Better control allows power generators to capitalize on the heat capture capabilities of supercritical unit designs. Unlike a drum-type boiler, the once-through, supercritical boiler does not have a large steam drum to store energy. Because there is no energy reserve, the control system must match, exactly and continuously, feedwater flow and boiler firing rate (both fuel and air) to the turbine�s steam energy needs, to deliver the desired generator power.
The ability of the control system to control operations tightly leads to stable, steady-state operation, without oscillation. This is critical, as steady-state, base load operation is key to achieving supercritical unit efficiency.
And once there is confidence that the control system can keep plant operations tightly controlled without the need for frequent operator intervention, power generators can augment plant efficiency by applying other complementary advanced automation and control technologies.
Pure sliding-pressure operation does not offer this kind of load or frequency response and is therefore generally not practiced. Note that for a typical 3,800-psia steam pressure rating, a (modified) sliding-pressure steam generator operates at subcritical pressures at all loads below about 73% maximum continuous rating (MCR).
Inverse response is when you increase gas or steam flow and get a decrease in pressure. Here is a paragraph describing it, from
As discussed above, load or pressure disturbances cause the water level within the drum boiler to swell and shrink due to complex phase changes between steam and water within the drum boiler. During a pressure disturbance transient condition in the boiler drum, the feed-water flow demand reflects an inverse response. In one example, an increased steam flow from the drum results in a decrease in pressure in the drum. The increased steam flow from the drum results in an inverse response of the feed-water demand. As a result, there is an increase in feed-water flow demand into the boiler. Addition of feed-water flow to the drum results in even further increased drum water level, since the water level in the drum may be already swelling due to increased bubbling phenomenon. In another example, a decrease in the steam flow rate from the drum results in an increase in pressure in the drum. As a result, there is a decrease in feed-water flow demand into the boiler. Reduction in feed-water flow to the drum results in even further decreased water level, since the water level in the drum may be already shrinking due to bubble collapsing phenomenon.
“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, See

18. Two Comments
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.
Decreasing β will risk violation of NERC Standard BAL a — 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.

19. 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.
ε1 is maximum acceptable steady-state freq deviation Hz in east interconnection.

20. 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.

21. 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(.) 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

22. Simulation System A B 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 A B
Con
Wind

23. Simulation Results

24. Simulation Results Conclusion:
Measures
CPS1
CPS2
0% wind penetration
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%
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%
Control fast variations of wind power within +- 1% of forecast
124.64%
Conclusion:
Wind degrades frequency performance due to inertia, no control, and variability.
These 3 issues need to be and can be addressed.

25. Regulation via rotor speed & pitch control
FUEL
Steam Boiler
Generator
CONTROL SYSTEM
Steam valve control
Fuel supply control
MVAR-voltage control
Wind speed
Gear Box
Real power output control
STEAM-TURBINE
WIND-TURBINE
Pitch control
Rotor speed 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.
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
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.

26. Manufacturers & some wind farms have it
See
Then why don’t they use it?

27. 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
[2] [North American Electric Reliability Corporation, “Special Report: Accommodating High Levels of Variable Generation,” April 2009, available at

28. 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

29. Solutions to degraded frequency performance
Increase control of the wind generation
Provide wind with inertial emulation & speed governing
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
Increase non-wind MW ramping capability during periods of expected high variability using one or more of the below:
Conventional generation
Load control
Storage
 Steam turbine plants 1- 5 %/min
Nuclear plants 1- 5 %/min
GT Combined Cycle %/min
Combustion turbines 20 %/min
 Diesel engines 40 %/min

30. Hybrid Wind Systems – Save Money, Enhance Frequency Regulation
200
400
600
800
1000
1200
1400
1600
1800 2 4 6 8 10 12
Time (s)
Wind Speed (s)
Hybrid Wind Systems – Save Money, Enhance Frequency Regulation
200
400
600
800
1000
1200
1400
1600
1800
-50 50
100
150
250
300
350
Time (s)
Power Command (MW)
Wind Power
CAES Power
NaS Battery Power ×10
HOLDEN
REDBRIDG
CHENAUX
CHFALLS
MARTDALE
HUNTVILL
NANTCOKE
WALDEN
COBDEN
MTOWN
GOLDEN
BVILLE
STRATFRD
JVILLE
WVILLE
STINSON
PICTON
CEYLON
RICHVIEW
LAKEVIEW
MITCHELL
PARKHILL
BRIGHTON
HANOVER
KINCARD
HEARN
DOUGLAS
200
400
600
800
1000
1200
1400
1600
1800
59.96
59.97
59.98
59.99 60
60.01
60.02
60.03
60.04
Time (S)
System Frequency (Hz)
Wind plant
Hybrid Wind Systems
Number of buses 60
Number of generators 25
Number of branches 96
Peak Load
6,110MW
Total Generation Capacity
10,995MW
Wind Power Capacity
545MW
CAES
Power Capacity
Compressor
30MW
Gas Turbine
75MW
CAES Energy Capacity
17,000MWh
NaS Battery Power Capacity
5.5MW
NaS Battery Energy Capacity
1.25MWh
200
400
600
800
1000
1200
1400
1600
1800
-100
-80
-60
-40
-20 20 40 60 80
100
Mismatch (MW)
With Storage
No Storage
Cost ($M)
Saving ($M)
Investment Cost
Operation Cost
155.15
221.83
481.40
Life time: 20 years

31. 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 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.

32. Conclusion: Select solution portfolio