wind difg2

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IEEE TRANSACTIONS ON POWER SYSTEMS 1

Utilizing DFIG-Based Wind Farmsfor Damping Subsynchronous Resonance

in Nearby Turbine-GeneratorsSherif Omar Faried, Senior Member, IEEE, Irfan Unal, Student Member, IEEE, Dipendra Rai, Student Member, IEEE,

and Jean Mahseredjian, Senior Member, IEEE

Abstract—The paper presents the potential use of supplementalcontrol of doubly-fed induction generator (DFIG)-based windfarms for damping subsynchronous resonance (SSR) oscilla-tions in nearby turbine-generators connected to series capacitivecompensated transmission systems. SSR mitigation is achievedby introducing a supplemental signal into the control loops ofthe DFIG voltage-sourced converter-based back-to-back. Thevalidity and effectiveness of the proposed supplemental controlare demonstrated on a modified version of the IEEE secondbenchmark model for computer simulation of subsynchronousresonance by means of time domain simulation analysis using theEMTP-RV program.

Index Terms—Doubly-fed induction generator, series capacitivecompensation, subsynchronous resonance mitigation, voltagesourced converter, wind energy.

I. INTRODUCTION

S ERIES capacitive compensation is a very economical wayfor increased transmission capacity and improved transient

stability of transmission grid. However, one of the hinderingfactors for the extensive use of series capacitive compensationis the potential risk of subsynchronous resonance (SSR), whereelectrical energy is exchanged with generator shaft system in agrowing manner which may result into damage of turbine-gen-erator shaft systems [1]. Therefore, mitigating SSR has been andcontinues to be a subject of research and development aiming atdeveloping effective SSR countermeasures [2]–[4].Wind energy is among the fastest growing renewable energy

technologies in the world. Increasing by approximately 30% ayear globally over the last decade, wind energy has proven tobe a clean, abundant and completely renewable source of en-ergy. Owing to the rapidly increasing use of wind power, theaspect of integrating high levels of wind power into the grid isbecoming more and more reality. Examples of large wind farmsin the United States are the 781.5-MW Roscoe wind farm inTexas, the 845-MW Shepherds Flat wind farm in Oregon, andthe 1550-MWAlta wind farm being developed in California [5].

Manuscript received November 24, 2011; revised February 29, 2012; ac-cepted April 18, 2012. Paper no. TPWRS-01139-2011.S. O. Faried, I. Unal, and D. Rai are with the Power Systems Research Group,

University of Saskatchewan, Saskatoon, SK S7N 5A9, Canada (e-mail: [email protected]; [email protected]; [email protected]).J. Mahseredjian is with the École Polytechnique de Montréal, Montréal, QC

H3C 3A7, Canada (e-mail: [email protected]).Color versions of one or more of the figures in this paper are available online

at http://ieeexplore.ieee.org.Digital Object Identifier 10.1109/TPWRS.2012.2196530

Fig. 1. Schematic diagram of the test benchmark.

As most large wind farms in North America employ DFIGwind turbines, their voltage-sourced converter-based back-to-backs (BtBs) offer independent control of the real and reactivepower. The use of these control capabilities have been recentlyproposed for damping power swings as well as inter-area os-cillations [6]–[9]. Virtually, no research has been reported onutilizing DFIG BtBs for damping SSR. This paper investigatesthe potential use of supplemental control of DFIG-based windfarms for damping subsynchronous resonance oscillations innearby turbine-generators. Time domain simulations are con-ducted on a test benchmark using the EMTP-RV.

II. TEST BENCHMARK

To evaluate the effectiveness of the proposed supplementalcontrol, the IEEE second benchmark model for computer sim-ulation of SSR is modified by the inclusion of a DFIG-basedwind farm as shown in Fig. 1 [10]. The shaft system of tur-bine-generator 1 (G1) consists of a high-pressure turbine (HP1),a low-pressure turbine (LP1), the generator rotor, and a rotatingexciter (EXC1). The shaft system of turbine-generator 2 (G2)consists of a high-pressure turbine (HP2), a low-pressure turbine(LP2), and the generator rotor. TheDFIG-based wind farm com-prises 333 1.5-MW, 0.575-kV wind turbines and is connectedvia a transformer to bus A through a short transmission line (85km). The data of this test benchmark are given in the Appendix.

III. DFIG-BASED WIND TURBINE MODEL AND CONTROL

The basic configuration of a DFIG wind turbine is shownin Fig. 2, where the stator of the induction machine is directlyconnected to the grid while a BtB partial-scale power converter

0885-8950/$31.00 © 2012 IEEE


2 IEEE TRANSACTIONS ON POWER SYSTEMS

Fig. 2. Schematic diagram of a DFIG wind turbine.

Fig. 3. Schematic diagram of a general control scheme of a DFIG BtBconverter.

(25% to 30% of the generator rating) connects its wound-rotorto the grid. The BtB converter consists of two voltage-sourcedconverters [rotor-side converter (RSC) and grid-side converter(GSC)] and a common dc bus. The mathematical model ofDFIG wind turbines has been well documented in the literature[11]–[15].The control of the DFIG wind turbine is achieved by con-

trolling the RSC and GSC converters utilizing vector controltechniques. Vector control allows decoupled control of both realand reactive power. The idea is to use a rotating reference framebased on an AC flux or voltage and then to project the currentson this rotating frame. Such projections are usually referred toas the d- and q- components of their respective currents. Forflux-based rotating frames, changes in the q- component lead toreal power changes, while changes in the d- component lead toreactive power changes. In voltage-based rotating frames (90ahead of flux-based frames), the effect is the opposite.Fig. 3 shows a general control scheme for the DFIG BtB con-

verter [16]–[18]. In such a scheme, the RSC operates in thestator flux reference frame while the GSC operates in the statorvoltage reference frame. The q-axis current of the RSC is usedto control the real power while the d-axis current is used for re-active power control. On the other hand, the d-axis current forthe GSC is used to control the dc link voltage to a constant levelwhile the q-axis current is used for reactive power control.

Fig. 4. Introducing an SSR supplementary control signal at the GSC reactivepower control loop.

Fig. 5. GSC supplemental controller.

TABLE ISUPPLEMENTAL CONTROLLER PARAMETERS FOR THREE CYCLES THREE-PHASEFAULT AT BUSES A AND B AND FOR THE DFIG LOCATED 126 KM FROM BUS A

TABLE IISUPPLEMENTAL CONTROLLER PARAMETERS FOR FOUR CYCLES

THREE-PHASE FAULT AT BUS B

As illustrated in Fig. 3, both RSC and GSC are controlled by atwo-stage controller. The first stage consists of very fast currentcontrollers regulating the rotor currents to references values thatare specified by slower power controllers (Stage-2). In normaloperation, the aim of the RSC is to control independently thereal and reactive power on the grid while the GSC has to main-tain the dc link capacitor at a set value regardless of the mag-nitude and direction of the rotor power and to guarantee con-verter operation with unity power factor (zero reactive power).The reference for the real power is given by the max-imum power tracking point (MPT) look-up table as a function


FARIED et al.: UTILIZING DFIG-BASED WIND FARMS FOR DAMPING SUBSYNCHRONOUS RESONANCE IN NEARBY TURBINE-GENERATORS 3

Fig. 6. Turbine-generator electrical powers and shaft torsional torques duringand after clearing a three-cycle, three-phase fault at bus B (compensation degree= 65%, supplemental control is not in service).

of the optimal generator speed. The reference for thereactive power of the RSC can be set to a certain value or tozero according to whether or not the DFIG is required to con-tribute with reactive power. The reactive power reference for theGSC , is “usually” set to zero. This means that theGSC exchanges only real power with the grid and, therefore,the transmission of reactive power from the DFIG to the gridis done only through the stator. However, the reactive powercontrollability of the GSC can be useful during the process ofvoltage reestablishment after clearing a system fault. The refer-ence signal is set to a constant value that depends onthe size of the converter, the stator/rotor voltage ratio and themodulation factor of the power converter.

IV. SUBSYNCHRONOUS RESONANCE DAMPING CONTROLLER

SSR damping is achieved by adding a supplementary signalat the GSC reactive power control loop as shown in Fig. 4. TheSSR supplemental control, shown in Fig. 5, has N channels thatutilize the modal speeds as control signals [19], [20]. These

Fig. 7. DFIG real and reactive powers, terminal voltage, and BtB dc linkvoltage during and after clearing a three-cycle, three-phase fault at bus B(compensation degree = 65%, supplemental control is not in service).

modal speeds are derived from the turbine-generator rotatingmass speeds as [21], [22]

(1)

where is the modal speed deviation matrix, is the eigen-vector matrix, and is the speed deviation matrix of the tur-bine-generator rotating masses. The rotating mass speeds canbe obtained using torsional monitor. Moreover, it is assumedthe availability of a wide-area network of synchronized phasormeasurement (SPM) units where those speeds can be down-loaded at the controller in real time without delay [23]–[25].Each modal speed as presented is separately phase and gainadjusted to provide damping for its corresponding oscillationsmode. The phase compensations are provided as

(2)

In the studies conducted in this paper, initial values of thesupplemental controller gains and time constants ( , ,and ) are chosen, using trial-and-errorapproach, such that they provide the best damping for corre-spondingmode of oscillations. The fine tuning of the parametersare performed with the help of repeated time domain simulationruns to minimize the cost function

(3)

where is fault clearing time and is the total simulationtime. The final values of the gain and time constants are givenin Tables I and II and the matrix is given in the Appendix.It is worth noting here that other control techniques can alsobe used for optimizing the supplemental control parameters.



Fig. 8. Turbine-generator electrical powers and shaft torsional torques duringand after clearing a three-cycle, three-phase fault at bus B (compensation degree= 65%, supplemental control is in service).

During steady-state, there will be no SSR feedback signal and,hence, the SSR damping signal becomes zero.

V. TIME DOMAIN SIMULATION RESULTS

For time-domain simulation studies, the synchronous andinduction generators are represented in the referenceframe by detailed models. The turbine-generators and DFIGshaft systems are represented by linear multi-mass-springdashpot systems. The transmission lines are modeled for thepresent study as transposed lumped parameters using seriesimpedance representation and the compensation degree isdefined by the ratio . The infinite bus is representedas a constant amplitude sinusoidal voltage at synchronousfrequency. Circuit-breakers are represented as ideal switcheswhich can open at current zero crossings. Dynamics of theturbine-generator excitation and governor systems are includedin the simulation model. In the investigations conducted in thispaper, the low voltage ride-through control of the EMTP-RVwind-turbine model is designed to meet Hydro Quebec re-quirements to voltage dips [26]. The wind-turbine is to stay

Fig. 9. DFIG real and reactive powers, terminal voltage, and BtB dc linkvoltage during and after clearing a three-cycle, three-phase fault at bus B(compensation degree = 65%, supplemental control is in service).

connected through a normally cleared three-phase fault anda delayed single line-to-ground fault. The wind plant shouldremain online for 150 milliseconds of three-phase fault, evenif the voltage at the high tension side of the wind plant step-uptransformer is reduced to zero.

A. SSR Damping at 65% Compensation Degree

Fig. 6 illustrates the time responses of the turbine-generatorelectrical powers and shaft torsional torques during and afterclearing a three-cycle, three-phase fault at bus B for the casewhen the supplemental controller is not in service. Fig. 7 illus-trates the time responses of the DFIG real and reactive powers,terminal voltage and the BtB dc voltage for the same case. It canbe seen from Fig. 6 that, at this compensation degree, the tur-bine-generator shaft torsional torques exhibit severe torsionalamplifications (instability). It can also be seen from Fig. 7 thatthe adverse effect of SSR extends its impact to the DFIG. Thecomparison between these two figures and Figs. 8–10 which il-lustrate the corresponding system time responses when the sup-plemental control of the DFIG is in service demonstrates the ef-fectiveness of such a controller in damping the torsional torquesin all turbine-generator shaft sections.In order to get an insight of the excited SSR mode com-

ponents and the effectiveness of the proposed controller inreducing these components, Fig. 11(a) and (b) shows thefrequency spectrums (obtained using fast Fourier transformanalysis) of the line current of the series capacitor compensatedtransmission line, the (LP1-GEN1) and (LP2-GEN2) shafttorsional torques for the study cases illustrated in Figs. 6 and 8,respectively. As it can be seen from this figure, at this compen-sation degree, the first torsional mode (24.65 Hz) is excited andits complement electrical mode (35.35 Hz) is clearly presentin the transmission line current. It can also be seen from the



Fig. 10. DFIG phase c stator current during and after clearing a three-cycle,three-phase fault at bus B (compensation degree = 65%, supplemental controlis in service, phase a, b, and c currents are almost identical).

Fig. 11. Frequency spectrums of the line currents of the series capacitorcompensated transmission line, (LP1-GEN1) and (LP2-GEN2) shaft torsionaltorques during and after clearing a three-cycle, three-phase fault at bus B[compensation degree = 65%, (a) Supplemental control is not in service,(b) Supplemental control is in service].

same figure that the amplitude of the excited torsional mode issignificantly reduced by the SSR supplemental controller.

B. Effect of the Fault Location on SSR Damping

The effect of the fault location on the effectiveness of the pro-posed supplemental control in damping SSR oscillations is ex-amined by changing the location of the three-cycle, three-phasefault from bus B to bus A. Although this is a severe disturbancesince the fault is virtually at the generator terminals as well asmuch closer to the DFIG, the series capacitor has no impactduring the fault duration The time responses of the turbine-gen-erator electrical powers and shaft torsional torques during andafter clearing the fault without and with the supplemental con-trol are shown in Fig. 12(a) and (b), respectively. The time re-sponses of the DFIG real and reactive powers, terminal voltageand BtB dc link voltage during the same event are also given inFig. 13(a) and (b) It can be seen from Fig. 12(a) that the ampli-tudes of the shaft torsional torques are relatively less than thosein Fig. 6. It can also be seen from Fig. 12(b) that the supple-mental control is capable of damping the SSR oscillations re-sulting from such a severe disturbance.

Fig. 12. Turbine-generator electrical powers and shaft torsional torques duringand after clearing a three-cycle, three-phase fault at bus A [compensation degree= 65%, (a) Supplemental control is not in service, (b) Supplemental control isin service].

C. Effect of the Fault Clearing Time on SSR Damping

The effect of the fault clearing time on the effectiveness ofthe proposed supplemental control in damping SSR oscillationsis explored at a different clearing time, namely four cycles. Thetime responses of the turbine-generator shaft torsional torquesduring and after clearing a four-cycle, three-phase fault at bus Bwithout andwith the supplemental control for this line length areshown in Fig. 14(a) and (b), respectively. As it can be seen fromthis figure, the supplemental control is capable also of dampingthe SSR oscillations resulting from such a disturbance at the newfault clearing time.

D. Effect of the Distance Between the DFIG Wind Farm andthe Turbine-Generators on SSR Damping

The effect of the distance between the DFIG wind farm andthe turbine-generators on the effectiveness of the proposed sup-plemental control in damping SSR oscillations is explored at a



Fig. 13. DFIG real and reactive powers, terminal voltage, and BtB dc linkvoltage during and after clearing a three-cycle, three-phase fault at bus A [com-pensation degree = 65%, (a) Supplemental control is not in service, (b) Supple-mental control is in service].

different length of transmission line A-C, namely 126 km. Thetime responses of selected shaft torsional torques during andafter clearing a three-cycle, three-phase fault at bus B withoutand with the supplemental control for this line length are shownin Fig. 15(a) and (b), respectively. The DFIG reactive poweroutput for the same disturbance is shown in Fig. 16. As it canbe seen from these figures, the supplemental control is capablealso of damping the SSR oscillations resulting from such a dis-turbance at the new DFIG location. It is worth noting here thatthe SSR damping controller parameters given in Table I in theAppendix are used for both DFIG wind farm location cases (85km and 126 km). In cases where the DFIG wind farm is locateda quite far distance from bus A, very wide reactive power mod-ulation would require the need for a self-tuning adaptive SSRdamping controller.

VI. CONCLUSION

This paper is believed to be the first to investigate the poten-tial use of a supplemental control of a DFIG-based wind farm indamping subsynchronous resonance in nearby turbine-genera-tors. SSR damping is achieved bymodulating the reactive powerof the grid-side converter. The effectiveness of the proposedsupplemental control in damping SSR at a high compensationdegree, namely 65% is demonstrated through detailed digitalcomputer simulations of a test benchmark. The results of the in-vestigations have shown that the proposed supplemental controleffectively damps subsynchronous torsional oscillations.The design of a self-tuning controller for the proposed SSR

damping controller is the subject of the authors’ current re-search. The technique is currently under the development stageand the results will be reported in a subsequent publication.Further research is needed in this area to bring the potential to

when the damping capability of renewable energy systems can

Fig. 14. Turbine-generator electrical powers and shaft torsional torques duringand after clearing a four-cycle, three-phase fault at bus B [compensation degree= 65%, (a) Supplemental control is not in service, (b) Supplemental control isin service].

be sold as ancillary service. The ultimate objective is to com-bine wind farms with conventional power plants and FACTSControllers so that together they provide the real and reactivemodulating powers in wide-area control of large power systems.

APPENDIX

The data of the IEEE second benchmark model for computersimulation of SSR are given in [10]. The data of the rest of thesystem are as follows:

Turbine-Generator Modal Speed Calculation Data [27]:The modal speeds are corresponding to the turbine-generatorshaft natural torsional frequencies which are found from theimaginary part of the eigenvalues of themass-spring system. Foreach eigenvalue, there is an eigenvector that has N componentswhere N is the number of masses. When the N components of



Fig. 15. Effect of the distance between the DFIG and the turbine-generatorson the (LP1-GEN1), (HP1-LP1), (LP2-GEN2), and (HP2-LP2) shaft torsionaltorques during and after clearing a three-cycle, three-phase fault at bus B [com-pensation degree = 65%, line A-C length = 126 km, (a) Supplemental control isnot in service, (b) Supplemental control is in service].

Fig. 16. DFIG reactive power output during and after clearing a three-cycle,three-phase fault at bus B (compensation degree = 65%, line A-C length =126 km, supplemental control is in service).

Fig. 17. Excitation system block diagram.

each eigenvector are normalized with respect to the largest com-ponent, the N mode shapes of torsional oscillations of all eigen-vectors can be found. The torsional modes involving shaft twistare commonly numbered sequentially according to mode fre-quency and number of phase reversals in the mode shape. Thus,Mode 0 signifies that the N masses oscillate in unison withouta shaft twist and Mode N has the Nth lowest frequency and amode shape of N phase reversals. The total number of modesincluding the rigid body mode (Mode 0) is equal to the numberof inertial elements in the spring-mass model.

Generator 1

Generator 2

Supplemental control parametersUncompensated transmission line parameters

Turbine-generator excitation system data (Fig. 17)

DFIG data1.5 MW, 0.575 kV, 60-Hz

BtB dc capacitor = 0.01 F, dc voltage = 1.15 kV.The system operating condition corresponds to

. power output from the turbine-generators (on tur-bine-generator 1, 600-MVA base). The DFIG power outputis . on the same base. The infinite busvoltage is 1.0 p.u.

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Sherif Omar Faried (S’88–M’88–SM’00) receivedthe B.Sc. and M.Sc. degrees from Ain Shams Uni-versity, Cairo, Egypt, in 1979 and 1984, respectively,and the M.Sc. and Ph.D. degrees from the Universityof Saskatchewan, Saskatoon, SK, Canada, in 1988and 1993, respectively, all in electrical engineering.He is currently a Professor of electrical en-

gineering in the Department of Electrical andComputer Engineering, University of Saskatchewan.His current research interests include powersystem dynamics, flexible AC transmission system

(FACTS), and power quality.Prof. Faried is a Registered Professional Engineer in the Province of

Saskatchewan.

Irfan Unal (S’09) was born in Zonguldak, Turkey.He received the B.Sc. degree in electrical engi-neering from Istanbul Technical University (ITU),Istanbul, Turkey, in 1991 and the M.Sc. degreein electrical engineering from the University ofSaskatchewan, Saskatoon, SK, Canada, in 2011.His research interest areas are flexible AC trans-

mission system (FACTS) controllers, power systemdynamics and control.

Dipendra Rai (S’07) received the B.E. degree inelectrical engineering from Tribhuvan University(T.U.), Nepal, in 2004 and the M.Sc. and Ph.D.degrees in electrical engineering from the Universityof Saskatchewan, Saskatoon, SK, Canada, in 2008and 2012, respectively.His research interest includes flexible AC trans-

mission system (FACTS) controllers, power systemdynamics and control.

Jean Mahseredjian (SM’82) graduated from ÉcolePolytechnique de Montréal, Montréal, QC, Canada,and received the M.A.Sc. and Ph.D. degrees in 1985and 1991, respectively.From 1987 to 2004, he was with IREQ

(Hydro-Québec), working on research and de-velopment activities related to the simulation andanalysis of electromagnetic transients. In December2004, he joined the Faculty of Electrical Engineeringat École Polytechnique de Montréal where he iscurrently a Professor.

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