Frequency control (MW-Hz) with wind 1 Iowa State University

Outline 1.MW-Hz time frames 2.Transient frequency control 3.Frequency governing 4.CPS1, CPS2 5.Simulations 6.Solutions 7.Conclusions 2

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

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

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

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 The greater the rate of change of frequency (ROCOF) following loss of a generator ∆P L, the lower will be the frequency dip. ROCOF increases as total system inertia ΣH i decreases. Therefore, frequency dip increases as ΣH i decreases. 7

Transient frequency control Nadir 2.75 sec Example: Ireland: ∆P L =432 MW=4.32 pu. ΣH i =475 sec 1. Governors 2. Load frequency sensitivity *2.75=49.38Hz 8

Transient frequency control Example: Estrn Interconnection: ∆P L =2900 MW=29 pu. ΣH i =32286 sec Nadir Hz z *1.5= Hz 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 (decreases denominator)  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 De- Commitment 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 Steam Boiler Generator CONTROL SYSTEM Steam valve control Fuel supply control MVAR- voltage control Wind speed Gear Box Generator CONTROL SYSTEM MVAR- voltage control Real power output control STEAM- TURBINE WIND- TURBINE The ability to control mech torque applied to the generator using pitch control & electromagnetic torque using rotor current control (to optimize C p 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. 12

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

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.” [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., [2] “Nordic Grid Code 2007 (Nordic Collection of Rules), Nordel. Tech. Rep., Jan 2004, updated [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 [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

Frequency Governing Characteristic, β 16 “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.” β,β, Source: J. Ingleson and E. Allen, “Tracking the Eastern Interconnection Frequency Governing Characteristic,” Proc. of the IEEE PES General Meeting, July 2010.

Reasons for decrease in β 17 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, See 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 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. ε 1 is maximum acceptable steady-state freq deviation Hz in east interconnection.

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.

CPS2 is 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 L 10 describes the interval within which |(ACE) 10min | should be controlled. B S =sum of B values for all control areas. ε 10 =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. A B Wind Con

Simulation Results

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 Steam Boiler Generator CONTROL SYSTEM Steam valve control Fuel supply control MVAR- voltage control Wind speed Gear Box Generator CONTROL SYSTEM MVAR- voltage control Real power output control STEAM- TURBINE WIND- TURBINE 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. Pitch control Rotor speed control 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,

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

Regulation via rotor speed & pitch control [1] “Wind Generation Interconnection Requirements,” Technical Workshop, November 7, 2007, available at F3BCC715D602/0/November7WindInterconnectionWorkshop.pdf. F3BCC715D602/0/November7WindInterconnectionWorkshop.pdf [2] [North American Electric Reliability Corporation, “Special Report: Accommodating High Levels of Variable Generation,” April 2009, available at 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.” 27

Regulation via rotor speed & pitch control [15] Draft White Paper, “Wind Generation White Paper: Governor Response Requirement,” Feb, 2009, available at SPONSE_REQUIREMENT_draft.doc.. SPONSE_REQUIREMENT_draft.doc 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. …” 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 b.Load control c.Storage 29  Steam turbine plants 1- 5 %/min  Nuclear plants 1- 5 %/min  GT Combined Cycle %/min  Combustion turbines 20 %/min  Diesel engines 40 %/min

Hybrid Wind Systems – Save Money, Enhance Frequency Regulation HOLDENREDBRIDGCHENAUXCHFALLS MARTDALE HUNTVILL NANTCOKE WALDENCOBDENMTOWN GOLDEN BVILLE STRATFRDJVILLE WVILLE STINSON PICTON CEYLONRICHVIEW LAKEVIEW MITCHELL PARKHILL BRIGHTON HANOVER KINCARD HEARN DOUGLAS Number of buses60 Number of generators25 Number of branches96 Peak Load6,110MW Total Generation Capacity10,995MW Wind Power Capacity545MW CAES Power Capacity Compressor30MW Gas Turbine75MW CAES Energy Capacity17,000MWh NaS Battery Power Capacity5.5MW NaS Battery Energy Capacity1.25MWh Time (s) Wind Speed (s) Cost ($M) Saving ($M) Investment CostOperation Cost Life time: 20 years 30

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. 31

Conclusion: Select solution portfolio 32