Presentation on theme: "Frequency control (MW-Hz) with wind"— Presentation transcript:
1Frequency control (MW-Hz) with wind Wind Generation Technology Short Course October 27, 2010 Iowa State UniversityJames D. McCalleyHarpole Professor of Electrical & Computer Engineering
2Outline MW-Hz time frames Transient frequency control Frequency governingCPS1, CPS2SimulationsSolutionsConclusions
3MW-Hz Time Frames 0+<t<2s; Inertial 2s<t<10s; Speed-governors10s<t<5m; AGCt=0+; Proximity5m, ED
4MW-Hz Time FramesThis is load decrease, shown here as a gen increase.Source: FERC Office of Electric Reliability available at:
5MW-Hz Time Frames=+Load FollowingRegulationSource: Steve Enyeart, “Large Wind Integration Challenges for Operations / System Reliability,” presentation by Bonneville Power Administration, Feb 12, 2008, available at
6Transient 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 bladesViolation of NERC criteria with penaltiesN-1: Frequency not below 59.6 Hz for >6 cycles at load busesN-2: Frequency not below 59.0 Hz for >6 cycles at load buses
7Transient 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.
8Transient frequency control Example: Ireland: ∆PL =432 MW=4.32 pu. ΣHi =475 sec49.35Nadir2.75 sec1. Governors2. Load frequency sensitivity*2.75=49.38Hz
9Transient frequency control Example: Estrn Interconnection: ∆PL =2900 MW=29 pu. ΣHi =32286 secNadirHzz*1.5= Hz
10Transient 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….
11Transient frequency control Green: Base CaseDark Blue: 2% Wind PenetrationLight Blue: 4% Wind PenetrationRed: 8% Wind PenetrationEstrn Interconnection: Frequency dip after 2.9GW Gen drop for Unit De-Commitment scenario at different wind penetration levels (0.6, 2, 4, 8%)
12Transient 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.FUELSteam BoilerGeneratorCONTROL SYSTEMSteam valve controlFuel supply controlMVAR-voltage controlWind speedGear BoxReal power output controlSTEAM-TURBINEWIND-TURBINE
13Transient frequency control What is the fix for this? Consider DFIG control systemSource: 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.
14Transient frequency control Add “inertial emulation,” a signal dω/dt scaled by 2H-2Hdω / dt
15Transient 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.” “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. “Nordic Grid Code 2007 (Nordic Collection of Rules), Nordel. Tech. Rep., Jan 2004, updated 2007. 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. “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.
16Frequency Governing Characteristic, β 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 Governing Characteristic,” Proc. of the IEEE PES General Meeting, July 2010.
17Reasons 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 loadMore speed drives which may reduce frequency sensitivity of induction motorsBasic idea of sliding pressure is that constant pressure requires throttling at lower loading levels and is therefore inefficient. The throttling can be eliminatedby 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.SeeConstant 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 (seeFor 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, fromAs 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
18Two CommentsWind 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 PerformanceEach 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.
19CPS1 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.
20CPS1If 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.
21CPS2is 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 ACEL10 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
22Simulation System A B Two Area System (Area A and Area B) Wind power is assumed in area AEach area consists of 10 conventional units, with inertia and with speed governing24 hour UC is run based on a load and wind forecastWind 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 unitsActual sec-by-sec p.u. value of load and of wind power data from one wind farm is used.ConABConWind
24Simulation Results Conclusion: MeasuresCPS1CPS20% wind penetration160%100%Reference case at 25% wind penetration78.80%88.89%Provide primary frequency control to wind turbines98.84%83.33%Provide wind with inertial emulation & primary frequency control109.58%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 forecast91.92%Control fast variations of wind power within +- 1% of forecast124.64%Conclusion:Wind degrades frequency performance due to inertia, no control, and variability.These 3 issues need to be and can be addressed.
25Regulation via rotor speed & pitch control FUELSteam BoilerGeneratorCONTROL SYSTEMSteam valve controlFuel supply controlMVAR-voltage controlWind speedGear BoxReal power output controlSTEAM-TURBINEWIND-TURBINEPitch controlRotor speed controlRotor 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, AugB. 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.
26Manufacturers & some wind farms have it SeeThen why don’t they use it?
27Regulation 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 :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 , 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.” “Wind Generation Interconnection Requirements,” Technical Workshop, November 7, 2007, available at [North American Electric Reliability Corporation, “Special Report: Accommodating High Levels of Variable Generation,” April 2009, available at
28Regulation via rotor speed & pitch control ERCOT says , “…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. …” Draft White Paper, “Wind Generation White Paper: Governor Response Requirement,” Feb, 2009, available at
29Solutions to degraded frequency performance Increase control of the wind generationProvide wind with inertial emulation & speed governingLimit wind generation ramp ratesLimit of increasing ramp is easy to doLimit of decreasing ramp is harder, but good forecasting can warn of impending decrease and plant can begin decreasing in advanceIncrease non-wind MW ramping capability during periods of expected high variability using one or more of the below:Conventional generationLoad controlStorage Steam turbine plants 1- 5 %/minNuclear plants 1- 5 %/minGT Combined Cycle %/minCombustion turbines 20 %/min Diesel engines 40 %/min
30Hybrid Wind Systems – Save Money, Enhance Frequency Regulation 2004006008001000120014001600180024681012Time (s)Wind Speed (s)Hybrid Wind Systems – Save Money, Enhance Frequency Regulation20040060080010001200140016001800-5050100150250300350Time (s)Power Command (MW)Wind PowerCAES PowerNaS Battery Power ×10HOLDENREDBRIDGCHENAUXCHFALLSMARTDALEHUNTVILLNANTCOKEWALDENCOBDENMTOWNGOLDENBVILLESTRATFRDJVILLEWVILLESTINSONPICTONCEYLONRICHVIEWLAKEVIEWMITCHELLPARKHILLBRIGHTONHANOVERKINCARDHEARNDOUGLAS2004006008001000120014001600180059.9659.9759.9859.996060.0160.0260.0360.04Time (S)System Frequency (Hz)Wind plantHybrid Wind SystemsNumber of buses60Number of generators25Number of branches96Peak Load6,110MWTotal Generation Capacity10,995MWWind Power Capacity545MWCAESPower CapacityCompressor30MWGas Turbine75MWCAES Energy Capacity17,000MWhNaS Battery Power Capacity5.5MWNaS Battery Energy Capacity1.25MWh20040060080010001200140016001800-100-80-60-40-2020406080100Mismatch (MW)With StorageNo StorageCost ($M)Saving ($M)Investment CostOperation Cost155.15221.83481.40Life time: 20 years
31How 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.