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Frequency Regulation Contribution Through Variable-Speed Wind Energy Conversion Systems


IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 24, NO. 1, FEBRUARY 2009

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Frequency Regulation Contribution Through Variable-Speed Wind Energy Conversion Systems
Juan Manuel Mauricio, Student Member, IEEE, Alejandro Marano, Student Member, IEEE, Antonio Gómez-Expósito, Fellow, IEEE, and José Luis Martínez Ramos, Senior Member, IEEE

Abstract—This paper presents a new method to enhance the participation of variable-speed wind energy conversion systems (WECS) in existing frequency regulation mechanisms. The proposed approach, based on a modi?ed inertial control scheme, takes advantage of the fast response capability associated with electronically-controlled WECS, allowing the kinetic energy stored by rotational masses to be partly and transiently released in order to provide earlier frequency support. An additional improvement is achieved by communicating the WECS response to conventional generators so that these can eventually take care of the full load imbalance. Several simulations using a two-area test system are performed to demonstrate the bene?ts of the proposed scheme. Index Terms—Frequency regulation, variable-speed generators, wind energy conversion.

I. INTRODUCTION HE increasingly widespread use of wind generation in power networks translates into a higher participation of this technology in the total system generation mix. In countries where the penetration of wind energy conversion systems (WECS) is already signi?cant, system operators are beginning to worry about the performance of the primary frequency regulation system, since those units do not currently cooperate to keep the frequency under control while the number of units capable of doing so is decreasing in relative terms. Accordingly, the need to study the way in which wind units could participate in system frequency support strongly arises [1]. Several kinds of machines are used in WECS, but variable-speed generators such as doubly fed induction machines (DFIM) and permanent magnet synchronous machines (PMSM) are prevailing among others [2]–[5]. An important feature of DFIM and PMSM is the possibility for their active and reactive power outputs to be controlled as required by system operators. Although the steady-state active power delivered to the grid by a WECS depends on the mechanical energy transferred from the wind, the electric power can be transiently controlled, to a certain extent, by resorting to the mechanical system kinetic energy. This is due to the capability of these machines to work at asynchronous speeds, increasing in
Manuscript received February 04, 2008; revised September 12, 2008. First published January 14, 2009; current version published January 21, 2009. This work was supported by the Spanish MEC and Junta de Andalucía under Grants ENE2007-62997 and P06-TEP-01882, respectively. Paper no. TPWRS-000612008. The authors are with the Department of Electrical Engineering, University of Seville, Seville, Spain (e-mail: j.m.mauricio@ieee.org). Digital Object Identi?er 10.1109/TPWRS.2008.2009398

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this way the wind energy transfer ef?ciency for a given wind speed while the mechanical stress is relieved to some extent. Traditionally, WECS do not participate in the system frequency support. Hence, wind units do not increase or decrease their production when the frequency falls or rises respectively, which means that they do not contribute to the system inertia. At current rates of wind power contribution to the total generation mix, the system inertia will decrease to inadequate values for the appropriate system frequency recovery, following a power imbalance or grid disturbance. This effect is mainly noticeable in frequency deviations occurring in small or isolated systems with an important penetration of wind power [6]. Still, increased wind power penetrations, such as those foreseen in Europe, will increasingly demand wind power to provide ancillary services at least like conventional power plants or better. The primary frequency regulation is based on a set of local controllers, each one responding to frequency deviations by adding or subtracting active power in proportion to the rated power of the respective unit, assuring in this way a new equilibrium point for the system. Later on, the secondary control must reset the frequency again to its nominal value. There are several proposals for implementing the primary frequency regulation in wind turbines. In [7] the control strategy adopted consists of an emulation of the proportional control implemented in conventional generators. Wind machines are forced to work keeping a regulation band for frequency control, thus not using their full capacity, by suitably combining both static converter and pitch control. In [8] the factors affecting the inertial response of a variable-speed WECS are studied. In [9] and [10] some techniques to emulate additional inertia using WECS are presented. The frequency control strategy is a combination of inertial control, using the kinetic energy stored in the rotating masses, and a proportional control. Once the transient contribution of the wind generator ?nishes, its rotor speed differs from the optimal value, which calls for an additional control action intended to recover it when the system frequency returns to a safe margin. In this work the WECS frequency support is provided by following a proportional control strategy similar to the one implemented in conventional units. The energy needed is taken from the kinetic energy stored in the rotating masses, leading to a variation of the rotor speed that must be reset afterwards. Owing to the limited value of the stored kinetic energy, the contribution of wind units is limited to short periods of time. An enhanced performance is achieved by letting nearby conventional generators be aware of the contribution of wind generators to frequency

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Fig. 1. Power system model with nonconventional generation.

support, accelerating in this way their reaction to the load imbalance that initially caused the frequency deviation. This article focuses on the short-term framework, ranging from fractions of a second to few seconds, where the mechanical power or torque from the wind can be considered constant. In the midterm frame, ranging from few seconds to minutes, mechanical power from the wind is perturbed by gusts and changes in wind speed, which can affect the frequency regulation of the overall power system. In order to attenuate this in?uence it is possible to modify the pitch angles or the output power, as proposed in [11], and also to consider the aggregated smoothing effect of a large number of WECS and wind farms, as done in [12] and [13]. In long-term scenarios, from few minutes to hours, the total energy generated by WECS depends on the wind variation during the day. In this context, actions must be taken in order to increase the power reserve of power systems, as studied in [14]. The control strategy is tested through simulations performed on detailed models by using PSS/E [15]. A test system with nonconventional power injection is used to assess the bene?ts and shortcomings of the method proposed in this paper, when compared with those appeared in the literature. xThe rest of the paper is organized as follows: in Section II the power system model used for frequency regulation tests is presented; then, the inertial control, which is one of the most suitable control methods for this application, is described in Section III. The control strategy proposed is described in Section IV. Performance tests, discussion and results are shown in Section V; ?nally, conclusions are given in Section VI. II. MODELS FOR FREQUENCY SIMULATION In this section the models adopted for the power system and nonconventional generation are presented. A. Power System Model In Fig. 1 a classical model for frequency regulation studies is shown. The box named Conventional Generation has the power reference as input and the generated power as output. This box models the dynamics of an equivalent machine of a system with different kinds of generation technologies (hydro turbine, gas turbine, steam turbine, alternative engine, etc.), along with its governor. is subtracted from The total system active power demand while the total power interchanged with the generated power is added. In order to take into account neighbor systems

Fig. 2. WECS based on (a) DFIM and (b) PMSM.

Fig. 3. Equivalent conversion system.

the nonconventional generation, a new term de?ned as is added. In steady state, the total power balance is then as follows: (1) stands for the secondary control or AGC power The term is a coordination signal coming from nonreference while conventional generators. The meaning of this latter signal, constituting one of the main contributions of this work, will be explained below. B. Nonconventional Generation In Fig. 2 the most commonly used variable-speed machines for WECS are depicted. Both can be considered as a conversion system between a mechanical force (wind) and an asynchronous electrical link with the rest of the power system, as shown in Fig. 3. In steady state, in order to maintain a desired speed holds. However, the electronic converter is able to control arbitrarily, and almost instantly, by the active power output

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resorting to the kinetic energy stored in the rotational masses. This translates into a change in the rotational speed, , that can take place only for a short period of time in order to assure remains inside its operational limits. that In this work, nonconventional power generation based on variable-speed machines is considered. In order to establish a control strategy two important features of the considered WECS must be taken into account: ? There is no control over the primary power source, since it depends on the wind. ? The active power injected by nonconventional generators can vary almost instantly (and transiently, as stated above). The ?rst point establishes an important limitation that must be taken into account in any control strategy. The lack of control over the primary power source prevents the possibility of maintaining an arbitrary power output in a continuous manner, but for relative short periods of time. For the case of conventional generation, this is possible by controlling the primary power source (e.g., for hydro generation by controlling the admission gate). On the other hand, the active power of nonconventional generators can be controlled almost instantly when compared with conventional generators such as hydro or steam units. Earlier works about the use of nonconventional generators to provide frequency regulation support, based on making them behave like conventional generators [9], [16], do not exploit the advantage mentioned in the second point above. III. INERTIAL CONTROL In the context of WECS, the so-called inertial control adds a signal to the power reference output to be tracked by the nonconventional machine equivalent controller [9], [16], [17]. This signal is given by (2) where is a constant weighting the frequency deviation weights the frequency deviation itself. derivative while When applying this strategy is the frequency deviation behind a high-pass ?lter, so that a permanent frequency deviation has no effect on the control strategy. Fig. 4 depicts the simpli?ed lay out of the inertial control. The model and control strategy actually employed are quite more complicated than the ones shown in this ?gure. In fact, transducers and communication delays, as well as nonconventional generation power limits, are taken into account in the simulations. It is worth noticing that the equivalent nonconventional machine recovers the optimal speed once the frequency transient is over. For this purpose, a power reference, forcing the speed to track a desired speed reference, is computed as follows: (3) where and are the design constants of the PI controller, which must be chosen in order to allow: 1) fast speed recovery;

Fig. 4. Inertial control simpli?ed lay out.

2) transient speed variation, for a relatively short period of time, so that nonconventional generators are able to inject the needed amount of active power to mitigate transient frequency deviations. A recovery time of about 20 s is fast enough to maintain a proper generator performance. The transients considered for frequency support are in the order of about 2–3 s. Then, a relatively slow PI controller would satisfy both requirements. Taking into account (2) and (3) the total active power reference for nonconventional generators is computed as follows: (4) As stated above, frequency transients normally occur during a short period of time, allowing certain simpli?cations to be made. is provided by a relatively slow PI controller, it Initially, as can be assumed that it will not vary in a few seconds. Hence, at least for the discussions below (not for simulation purposes), could be considered as a constant. Moreover, as the electric power is regulated by a very fast power electronic converter, it can be assumed that there is no dynamics between the power . reference and the nonconventional total power injection These simpli?cations lead to (5) is the injected power before the frequency transient. where In order to analyze how the inertial control affects the rest of the power system, the model in Fig. 1 is considered. The relaand the frequency deviation tionship between the power sum can be obtained as follows:

Then, considering the power pression is obtained:

as in (5), the following ex-

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Hence, the considered inertial control translates into a system . This value can be established arbitrarily inertia given by . So, positive values of increase the system by varying inertia. In practical applications this is possible just inside some feasible margins. Special attention must be given to the frequency proportional , the original damping term is term. For positive values of increased. Therefore, large positive values provide a better frequency oscillation damping but, as will be shown by simulation results, this excites other oscillation modes related with frequency stability. The main inertial control shortcomings are related with the fact that it does not take into account the bene?cial characteristics of nonconventional generators, such as the fast active power response and the capability to arbitrarily establish a new power output inside some feasible margins. By using inertial control the system inertia is incremented, but there is no direct frequency support. Thus, the inertial control could mask load changes, leading conventional generators to delay their response when rejecting these perturbations. IV. PROPOSED CONTROL The control strategy proposed takes advantage of the fast power injection capability of nonconventional generators, while not masking sudden load changes. This is important in order to assure that conventional generators reject load perturbations as fast as possible. A very important aspect of the proposed strategy is that it does not make nonconventional generators to behave like conventional ones. On the contrary, it takes advantage of their faster response. A. Transient Primary Regulation The proposed strategy relies on a conventional primary regulation, performed in a transient manner. The output from the proposed controller is considered as an additional power reference to be tracked by the nonconventional equivalent machine controller. This reference signal can be de?ned as (6) where is the droop constant, as used traditionally. The variis related with the frequency measured in the interable connection bus between nonconventional generators and the rest of the power system, as will be de?ned next. As explained above, nonconventional generators can not afford a permanent system frequency deviation, since they can only act in a transient way using the stored kinetic energy. For this reason, the frequency term used in (6) is the result of a washout ?lter, as can be seen in Fig. 5. Actually, this is one of the main differences between the method proposed in this paper and previous approaches [7]. As noted earlier, inertial control makes WECS to work as synchronous generators. This approach is very interesting because the WECS inertia contributes to that of the rest of the power system. However, variable-speed WECS have an important advantage over synchronous machines, namely their very

Fig. 5. Lay out of the proposed control strategy and WECS model.

fast active power injection control. The proposed controller takes advantage of this important feature by considering the frequency deviation, instead of the frequency derivative, in the control law. As in the case of the inertial control, a slow PI controller (3) is used to recover the optimal rotor speed after the frequency is comtransient deviation. The total active power reference puted using (4). B. Power Generation Coordination The proposal depicted in Section IV-A is enough to improve the frequency response, as will be shown by means of simulations. However, an additional action can be taken to get an even better frequency behavior. Following a power imbalance, such as an unexpected demand , the active power generated by nonconventional increase, quickly increases to avoid the frequency fall. generators As this increased power can last just for a few seconds, conventional generators should eventually take charge of the increased . demand by shifting their generation, , in order to get slows down to a certain extent the But the fast increment in response of conventional generators. To avoid this undesirable effect, a coordination between nonconventional generators and a selected set of regulating conventional units is proposed. This is based on injecting the additional signal (7) where the constant ventional generator is the participation factor for each consupporting the nonconventional genera-

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Fig. 6. Two-area four-generator test system with nonconventional generation added at bus 12.

tion. This set of constants must be computed in order to comply with

TABLE I MODEL CONSTANTS USED FOR THE SIMULATIONS

Using this strategy, conventional units will realize the real magnitude of the power imbalance since the very beginning, and will start earlier to take charge of the active power generated by nonconventional generators, the contribution of which may not last for more than a few seconds. In Fig. 5 a diagram is shown containing the proposed control strategy and the simpli?ed model of the WECS. V. SIMULATIONS Several simulations have been performed in order to demonstrate the bene?ts provided by the proposed method when including nonconventional generation into the frequency support scheme. For this aim the program PSS/E is employed. The power system used for the simulations is taken from [18, Example 12.6], intended to study interarea oscillations. Such oscillations are quite noticeable using the proposed parameters. The system consists of four 900-MVA conventional generators, split into two areas. Area 1 includes generators 1 and 2, the whole area load being connected to bus 7. Generators 3 and 4 are located in area 2, bus 9 being the loading bus. Between bus 7 and 9 there is a tie-line interconnection with an intermediate bus 8. Each generator incorporates an automatic voltage regulator (AVR) and a power system stabilizer (PSS). To make the study of the frequency regulation possible, prime movers and turbine models are added to the system. For this purand are considered hydro units and are modeled pose, and are in PSS/E using the so-called IEEEG2, while modeled as thermal units using in PSS/E the so-called TGOV1 model. IEEEG2 and TGOV1 are both used with the default values. Some modi?cations are made to the original network in order to include the nonconventional generation. For this purpose a new bus is added, connected to bus 5 through a line which is electrically identical to the one connecting buses 5 and 6. The nominal value of the nonconventional generation is 500 MW, being less than 20% of the total system generation capacity. is 3.5. Fig. 6 The equivalent inertial constant of the WECS depicts the total model. The constants of the model shown in Fig. 5 are used in the simulations with the values depicted in Table I.

Fig. 7. Inertial control: frequency response for different values of

K

.

A. Inertial Control Simulations The ?rst strategy tested is the one based on existing inertial control. The aim is to assess the frequency behavior for different values of the constant in (2), while is chosen to mainunder 600 MW . Some shortcomtain power ings of this strategy emerge from these simulations. Fig. 7 shows the frequency behavior when a sudden load increment at bus 7 occurs. This causes a fall in the system frequency until the generators manage to reject the load perturbation, remaining the characteristic steady-state error associated

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Fig. 8. Inertial control: power injected by nonconventional generation for dif. ferent values of

K

Fig. 9. Frequency response comparison: without support by nonconventional generation (NC Gen.), with inertial control, and the two versions of the proposed control scheme.

with conventional units speed governors (in these simulations the existence of the secondary control is ignored). As can be seen, the best performance is reached for positive values of but, as explained in Section III, this excites the interconnection power oscillations. Assigning negative values to slightly damps the interarea oscillations, at the cost of signi?cantly increasing the frequency oscillation. In Fig. 8 the power injected by nonconventional generation is . In general, using this strategy, shown for different values of the injected power is quite oscillatory, especially when interarea oscillations appear, since the injected power depends on bus 12 frequency differentiation. Again, it can be noticed that as increases, the high-frequency oscillation is more and more relevant but, at the same time, the frequency regulation improves. B. Comparison of Strategies In the next simulations a sudden load increment of 200 MW at bus 7 is considered. The frequency response for each of the following cases is compared: ? without frequency support from nonconventional generators (NC Gen.); ? with the inertial control strategy, considering a positive value; ? with the proposed control, without coordination with con; ventional generators ? with the proposed control and coordination with gener. ator In Fig. 9 the frequency at bus 8 is shown. This bus, placed in a middle position between the two areas, is the best one to represent the frequency response of the whole considered system. As can be observed, without support from nonconventional generation, the frequency response has an important drop. The inertial control reduces this frequency decrement and makes it slower, which is in accordance with the increased inertia this strategy brings about. However, oscillations in the range of the interarea mode (around 0.7 Hz) arise. The same ?gure shows the frequency response with the proposed controller in its two versions, with and without coordinaFig. 10. Power injected by nonconventional generation: with inertial control and the two versions of the proposed control (Base: 100 MVA).

tion between nonconventional generators and generator . In absence of coordination the frequency drop is reduced by almost 50% compared with the case when no support from nonconventional generation is present. When the coordinating signal is considered, an improvement in the frequency support is obtained. This is achieved by making aware that nonconventional generators are contributing transiently to the frequency is considerably slower than that regulation. The response of of the nonconventional equivalent generation, which is only responsible for the quick power injection following the frequency perturbation, but it is helpful to provide frequency support at the end of the frequency transient. The oscillatory behavior of the injected power can be clearly observed in Fig. 10, where it is evident that the amplitude of power oscillations is much higher when the inertial control is adopted. On the other hand, the amount of injected power is greater during the ?rst peak with both versions of the proposed controller. Although the amount of transiently injected active

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Fig. 11. Equivalent nonconventional machine speed: with inertial control and the two versions of the proposed control.

Fig. 13. Mechanical powers of the conventional machines using the proposed control, with and without coordination.

In Fig. 13 the mechanical powers of the conventional machines, with and without coordination, are shown. In the coordimechanical power is greater during the nated case, generator transient. This power increase improves the frequency support, being helpful at the same time for nonconventional machines to recover their optimal speed. VI. CONCLUSION The increased participation of WECS in the overall generation mix affects conventional frequency regulation schemes in two ways. First, because of the reduction, in relative terms, of the total system inertia caused by the asynchronous power conversion and, second, due to the lack of participation of this generation in frequency support mechanisms. However, the fast response capability associated with electronically-controlled WECS, compared to that of conventional generation systems, can be taken advantage of to improve the transient performance of existing frequency regulation procedures. This paper presents a new control approach aimed at exploring this possibility. The proposed method enhances existing inertial control schemes by considering an additional power reference signal, transiently provided by a primary frequency regulator. This allows a fraction of the kinetic energy stored in rotational masses to be released in order to provide earlier frequency support. An additional improvement is achieved by communicating the WECS response to conventional generators, so that these can take care of the full power imbalance that caused the frequency deviation. Several simulations are carried out using a well-known twoarea system, to which nearly 20% of nonconventional generation is added. Step responses show a notable reduction of frequency oscillations when the proposed method is adopted, particularly if the WECS anticipated response is communicated to slower conventional generators. In all cases, this is achieved by keeping all relevant variables, including rotor speeds, within acceptable limits. Further research should be directed to devise new methods capable of better damping interarea oscillations.

Fig. 12. Power reference p from nonconventional generators to G .

power is signi?cant, this is totally permissible for nonconventional generators, considering that in this case the transient increment of power is less than 20% of their initial production and that it lasts for a relatively short period of time. The additional power injected by nonconventional generators during the frequency transient is taken from the energy stored in the rotating masses inertia of the equivalent WECS. In Fig. 11 it is shown that the rotor speed fall, with both versions of the proposed controller, does not exceed 10% of the initial speed, and that it evolves smoothly. The optimal speed is recovered in less than 30 s with coordination and a bit later when coordination is not present. is similar to that used when secThe coordinating signal ondary frequency regulation is applied in a power system. As it is known, these inputs are computed by strategies such as AGC regulation. In this work, besides this secondary regulation reference, the use of an additional signal communicating the production of nonconventional generators is proposed. This signal may be distributed among some of the conventional units according to (7). The use of this strategy improves the global power system response against frequency perturbations, as demonstrated by the simulations presented above. Fig. 12 presents the evolution of the coordinating signal sent to the conventional unit in charge in this case. of this task,

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REFERENCES [1] European Wind Energy Association (EWEA), Large Scale Integration of Wind Energy in the European Power Supply: Analysis, Issues and Recommendations, 2005. [Online]. Available: http://www.ewea.org/. [2] N. Ekanayake and J. Jenkins, “Comparison of the response of doubly fed and ?xed-speed induction generator wind turbines to changes in network frequency,” IEEE Trans. Energy Convers., vol. 19, no. 4, pp. 800–802, Dec. 2004. [3] R. Pena, J. Clare, and G. Asher, “A doubly fed induction generator using back-to-back PWM converters supplying an isolated load from a variable speed wind turbine,” Proc. Inst. Elect. Eng., Elect. Power Appl., vol. 143, no. 5, pp. 380–387, Sep. 1996. [4] J. Rodriguez-Amenedo, S. Arnalte, and J. C. Burgos, “Automatic generation control of a wind farm with variable speed wind turbines,” IEEE Power Eng. Rev., vol. 22, no. 5, pp. 65–65, May 2002. [5] J. G. Slootweg, S. W. H. de Haan, H. Polinder, and W. L. Kling, “General model for representing variable speed wind turbines in power system dynamics simulations,” IEEE Trans. Power Syst., vol. 18, no. 1, pp. 144–151, Feb. 2003. [6] J. R. S. F. D. O. M. Lalor and G. Ritchie, “Dynamic frequency control with increasing wind generation,” in Proc. IEEE Power Eng. Soc. General Meeting, Jun. 6–10, 2004, vol. 2, pp. 1715–1720. [7] J. de Almeida and R. G. Lopes, “Participation of doubly fed induction wind generators in system frequency regulation,” IEEE Trans. Power Syst., vol. 22, no. 3, pp. 944–950, Aug. 2007. [8] A. Mullane and M. O’Malley, “The inertial response of induction-machine-based wind turbines,” IEEE Trans. Power Syst., vol. 20, no. 3, pp. 1496–1503, Aug. 2005. [9] J. Morren, S. de Haan, W. Kling, and J. Ferreira, “Wind turbines emulating inertia and supporting primary frequency control,” IEEE Trans. Power Syst., vol. 21, no. 1, pp. 433–434, Feb. 2006. [10] G. Lalor, A. Mullane, and M. O’Malley, “Frequency control and wind turbine technologies,” IEEE Trans. Power Syst., vol. 20, no. 4, pp. 1905–1913, Nov. 2005. [11] B. Rawn, P. Lehn, and M. Maggiore, “Control methodology to mitigate the grid impact of wind turbines,” IEEE Trans. Energy Convers., vol. 22, no. 2, pp. 431–438, Jun. 2007. [12] T. Nanahara, M. Asari, T. Sato, K. Yamaguchi, M. Shibata, and T. Maejima, “Smoothing effects of distributed wind turbines. Part 1. coherence and smoothing effects at a wind farm,” Wind Energy, vol. 7, pp. 61–74, 2004. [13] T. Nanahara, M. Asari, T. Maejima, T. Sato, K. Yamaguchi, and M. Shibata, “Smoothing effects of distributed wind turbines. Part 2. coherence among power output of distant wind turbines,” Wind Energy, vol. 7, pp. 75–85, 2004. [14] G. Dany, “Power reserve in interconnected systems with high wind power production,” in Proc. IEEE Power Tech. Conf., Porto, Portugal, Sep. 10–13, 2001, pp. 6–. [15] Power Technologies International, PSS/E-30.1 Program Operation Manual (2005). [16] R. de Almeida, E. Castronuovo, and J. Lopes, “Optimum generation control in wind parks when carrying out system operator requests,” IEEE Trans. Power Syst., vol. 21, no. 2, pp. 718–725, May 2006. [17] F. M. Hughes, O. Anaya-Lara, N. Jenkins, and G. Strbac, “Control of DFIG-based wind generation for power network support,” IEEE Trans. Power Syst., vol. 20, no. 4, pp. 1958–1966, Nov. 2005. [18] P. Kundur, Power System Stability and Control.. New York: McGraw-Hill, 1993.

Juan Manuel Mauricio (S’00) was born in Argentina in 1977. He received the electrical engineering degree from the National University of Comahue, Neuquén, Argentina, in 2003. He is currently pursuing the Ph.D. degree in electrical engineering at the University of Seville, Seville, Spain. His primary areas of interest are power systems modeling and control and FACTS.

Alejandro Marano (S’04) was born in Argentina in 1977. He received the electrical engineering degree from the University of Malaga, Malaga, Spain, in 2001. He is currently pursuing the Ph.D. degree in electrical engineering at the University of Seville, Seville, Spain. His primary areas of interest are voltage stability, power systems control, and optimization applied to electrical engineering.

Antonio Gómez Expósito (F’05) was born in Spain in 1957. He received the electrical and doctor engineering degrees from the University of Seville, Seville, Spain. Since 1982, he has been with the Department of Electrical Engineering, University of Seville, where he is currently a Professor and Chairman of the Department. His primary areas of interest are power system optimization, state estimation, and digital signal processing.

José Luis Martínez Ramos (SM’04) was born in Dos Hermanas, Spain, in 1964. He received the Ph.D. degree in electrical engineering from the University of Seville, Seville, Spain. Since 1990, he has been with the Department of Electrical Engineering, University of Seville, where he is currently a Professor. His primary areas of interest are active and reactive power optimization and control, power system analysis, and electricity markets.

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