THE ELECTRICITY industry worldwide is turning increasingly

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1 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 20, NO. 4, NOVEMBER Frequency Control and Wind Turbine Technologies Gillian Lalor, Student Member, IEEE, Alan Mullane, Member, IEEE, and Mark O Malley, Senior Member, IEEE Abstract Increasing levels of wind generation has resulted in an urgent need for the assessment of their impact on frequency control of power systems. Whereas increased system inertia is intrinsically linked to the addition of synchronous generation to power systems, due to differing electromechanical characteristics, this inherent link is not present in wind turbine generators. Regardless of wind turbine technology, the displacement of conventional generation with wind will result in increased rates of change of system frequency. The magnitude of the frequency excursion following a loss of generation may also increase. Amendment of reserve policies or modification of wind turbine inertial response characteristics may be necessary to facilitate increased levels of wind generation. This is particularly true in small isolated power systems. Index Terms Frequency control, power system control, power system security, wind energy, wind power generation. NOMENCLATURE Swept area of wind turbine ( ). Blade pitch ( ). Power coefficient. Current (A). Gains. Supplementary control loop constant. Per phase mutual inductance (H). Per phase rotor inductance (H). Per phase stator inductance (H). (H). Flux linkage (Wb). Number of machine poles. Accelerating aerodynamic power (MW). Differential operator. Density of air ( ). Electromagnetic torque ( ). Reference electromagnetic torque ( ). Reference torque ( ). Supplementary control loop torque ( ). Time constant (s). Wind speed (m/s). Voltage (V). Reference frame angular velocity (rad/s). Manuscript received January 19, 2005; revised May 14, This work has been conducted in the Electricity Research Centre, University College Dublin, which is supported by Electricity Supply Board (ESB) Networks, ESB Power Generation, ESB National Grid, Commission for Energy Regulation, Cylon, Airtricity, and Enterprise Ireland. Paper no. TPWRS The authors are with the Electricity Research Centre, University College Dublin, Dublin 4, Ireland ( gill@ee.ucd.ie; alan.mullane@ee.ucd.ie; mark.omalley@ucd.ie). Digital Object Identifier /TPWRS Shaft speed (rad/s). Rotor electrical angular velocity (rad/s). A. Subscripts, Direct, quadrature axis component., Integral, proportional., Rotor, stator. I. INTRODUCTION THE ELECTRICITY industry worldwide is turning increasingly to renewable sources of energy to generate electricity. Environmental concerns about fossil-fueled conventional generators, the desire to increase the diversity and security of fuel supply, and increasing fossil fuel costs are all motivating factors behind this upward trend. Global targets for the reduction of carbon dioxide (CO ) and other greenhouse gases have been introduced [1] and separate targets for minimum quantities of electricity generated from renewable energy sources have also been established in many parts of the world [2]. Wind is the fastest growing and most widely utilized of the emerging renewable energy technologies in electricity systems at present, with a total of approximately 40 GW installed worldwide at the beginning of 2004 [3]. However, the majority of wind resources are still untapped, and the potential for energy from wind generation is vast. Constant advances in technology and the relatively low capital costs when compared with other forms of renewable energy are significant contributing factors to the ongoing rapid growth in the proportion of electricity being generated from wind. The ease with which wind generation is integrated into existing electricity systems depends on a number of factors, both technical and regulatory [3]. Technical aspects that need to be considered include the amount and location of wind generation, wind turbine technology, and the size and characteristics of the electricity system. Regulatory issues, such as compliance with existing system operator rules and regulations, also arise. Of the technical aspects that need to be considered, system inertia plays an extremely important role as it determines the sensitivity of system frequency to supply demand imbalances. The lower the system inertia, the faster the frequency will change if a variation in load or generation occurs. Large interconnected electricity systems generally have sizeable system inertia and large frequency deviations from nominal are rare. However, frequency deviations on small, isolated electricity systems, when they occur, tend to be more sizeable. When connecting wind turbines to small isolated power systems, their contribution to system inertia must be considered. The addition of synchronous generation to a power system intrinsically increases the system inertial response. This intrinsic increase does not necessarily occur with the addition of wind turbine generators due to their /$ IEEE

2 1906 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 20, NO. 4, NOVEMBER 2005 differing electromechanical characteristics. Therefore, the displacement of conventional synchronous generation with wind generation may result in an erosion of system inertial response resulting in increased rates of change of frequency (ROCOF) and larger frequency excursions. In small isolated systems, these phenomena are particularly challenging due to low system inertia. Where wind turbines are found to severely impact on system inertial response, system operators need to consider altering their frequency control strategies to avoid large rates of change of frequency and/or large frequency excursions. Ireland is experiencing a rapid increase in wind generation and has recently completed the development of transmission and distribution grid codes for wind [4], [5]. The main issues that are addressed, similar to other wind grid codes developed, are the specific requirements for frequency, voltage, and fault ride through behavior [4], [6]. As a small system with a peak load in the region of 6100 MW at present and relatively low inertia, frequency control on the Ireland system is an important issue. This paper examines the impact of increasing wind penetration on frequency control on the Ireland electricity system. A brief outline of common wind generation technologies is given in Section III. The wind turbine generator models used in this study are presented in Section IV, and the test system is described in Section V. The effects on system frequency control of increasing wind generation and the opportunities for the introduction of supplementary control on wind turbine generators are presented in Section VI. Conclusions are presented in Section VII. II. WIND GENERATION TECHNOLOGY Wind turbine generators (WTGs) can be divided into two basic categories: fixed speed and variable speed. A fixed-speed WTG generally uses a squirrel-cage induction generator to convert the mechanical energy from the wind turbine into electrical energy. During a frequency excursion, the relationship between the system frequency and the electromagnetic torque of any induction machine will determine the inertial response. As there is a strong coupling between the squirrel-cage induction generator stator and the power system, and due to the low nominal slip of 1% 2% [7], any deviations in system speed will result in a change in rotational speed. This linking of rotor speed with system speed gives rise to an inertial response from the fixed-speed WTG when the system frequency falls. Variable-speed WTGs can offer increased efficiency in capturing the energy from wind over a wider range of wind speeds, along with better power quality and the ability to regulate the power factor, by either consuming or producing reactive power. Doubly fed induction generator (DFIG) and multipole synchronous generator are popular types of variable speed WTGs. Both forms of generator have power electronic converters between the electrical machine and the power system. The multipole synchronous generator allows variable-speed operation by employing a back-to-back ac/dc/ac converter attached to the stator of the synchronous machine. As a result, the stator is isolated from and, consequently, unaffected by any changes in the frequency of the power system. Therefore, the power output from the WTG does not change and no inertial response is obtained during a frequency event. The power electronic converter in the DFIG, on the other hand, is attached to the rotor. The rotor is connected to the power system through this back-to-back ac/dc/ac converter, while the stator is connected directly to the power system. The net power output from the DFIG is the sum of the power outputs from both the stator and the rotor [8], [9]. During a system frequency excursion, any inertial response provided by the DFIG depends on the relationship between the electromagnetic torque of the machine and system frequency. This relationship, in turn, depends upon the type of controllers used in the converter and the parameters of the controllers [10]. III. WTG MODELING The operation and behavior of a induction generator is well documented [11], and various models have been developed and evaluated. The model used for the fixed-speed wind turbines in this study is the fifth-order - model of [12], which was found to have very good accuracy in simulating the rotor speed, electromagnetic torque, both active and reactive power, and stator currents. An inertial constant of 3.5 s is assumed for the fixedspeed WTG models used in this paper [8]. The fifth-order - induction machine model is also employed in the case of the DFIG wind turbine. However, the addition of the power electronics converter and related controllers to this induction machine model is necessary to model the behavior of the DFIG. Field-orientated control (FOC) is a prevalent form of controller setup utilized in the control of DFIGs [10], [13]. This type of controller is implemented in the DFIG model for this paper and further details of the model used for the DFIG WTGs may be found in [10]. Control of electromagnetic torque allows for the control of the speed, the basis of the variable speed nature of the DFIG wind turbine. FOC allows for the independent control of electromagnetic torque and stator reactive power. By the selection of an appropriate reference frame in the controller of the back-to-back ac/dc/ac converter, it is possible to have independent control of the electromagnetic torque through the control of a single variable: the rotor current. The equation for the electromagnetic torque, written in terms of rotor currents, reduces from through the appropriate choice of the reference frame, such that,to The control of may also be simplified considerably through the careful design of the - and -axes voltages, such that and (1) (2) (3) (4)

3 LALOR et al.: FREQUENCY CONTROL AND WIND TURBINE TECHNOLOGIES 1907 where and are auxiliary signals in the controller reference frame and are the outputs from the -axis and -axis proportional integral current controllers where,,, and are the proportional and integral gains for the and axes current controllers, respectively, and and are the reference and axes rotor currents. A more detailed description of (3) (6) is provided in [12]. Therefore, the full model of the DFIG wind turbine consists of the standard fifth-order induction machine - model and the FOC, modeled using (3) (6) above. This model, combined with the system model described in Section V, can be used to examine the influence that increasing proportions of DFIG wind turbines will have on system frequency control. Wind model input assumptions vary from constant torque to constant power [13], [14]. The frequently made assumption of constant torque means any changes in shaft speed will result in a change in captured aerodynamic power. The constant power assumption is also sometimes applied. The captured aerodynamic power is given by (7) and depends on air density, swept area of wind turbine, the power coefficient, and wind speed The motivation behind the constant power assumption is that remains constant for any changes in shaft speed. This is achieved by varying the blade pitch. The effect on the output of the WTG models is examined for the both the assumption of constant power and constant torque. IV. TEST SYSTEM A. Ireland Electricity System The Ireland electricity system is a small isolated system, consisting of two ac interconnected 50-Hz power systems operated by Northern Ireland Electricity (NIE) and Electricity Supply Board National Grid (ESBNG). The system currently has a peak load of approximately 6100 MW, and system load is forecast to grow by between 3% and 4% per annum for the next six years [15], [16]. Reheat and nonreheat thermal generators, simple cycle gas turbines, combined cycle gas turbines, and limited hydroelectric generation, along with a single pumped storage station, comprise the conventional generation on the Ireland system at present. The system also has a single HVDC interconnection to Scotland, with a capacity of 500 MW. However, it should be noted that it is currently not operated above 400 MW. At present, the installed wind capacity on the Ireland system of approximately 300 MW [17] is rapidly increasing and is expected to reach 1000 MW within the next three years. In order to meet the targets of 13.2% of all electricity in the Republic of Ireland and Northern Ireland s proportion of the U.K. target of 10% of all electricity to come from renewable sources by 2010 (5) (6) (7) [2], a total of at least 1300 MW of wind generation is required on the Ireland system by This signifies a much more rapid increase in wind generation than predicted system load over the next five years, resulting in a large increase in the proportion of wind generation on the Ireland system. However, if the rate of installation of wind generation continues to follow current trends on the Ireland system, the capacity of wind generation in 2010 could easily exceed that required to meet the EU targets. B. Frequency Control In accordance with the system grid codes [18], [19], frequency regulation can be provided by each generator on the system, by virtue of a droop governor, with a droop setting of 4%. Primary operating reserve (POR), the reserve available between 5 and 15 s subsequent to an event, corresponds to 75% of the largest infeed onto the Ireland system. At present, the largest infeed is 422 MW, thus making the primary reserve requirement 317 MW. This primary reserve requirement is divided such that the ESBNG and NIE systems provide 67% (211 MW) and 33% (106 MW), respectively. Sources of POR include spinning reserve from generating units online and static reserve, and the proportion of the POR provided by spinning and static reserve sources varies with time of day. Static reserve consists of blocks of reserve that are available almost instantaneously when tripped by the system frequency falling below the predetermined frequency setting of each block. These frequency settings range between 49.5 and 49.3 Hz. For example, at night, up to four 73-MW units of the pumped storage station may be operating in pumping mode, which trip when the predetermined frequency levels are reached, to provide static reserve. In general, the contribution of the pumped storage station to POR depends on the operational mode in which it is running and varies depending on system conditions and time of day. C. System Model A single busbar model of the Ireland electricity system is used in this paper to model the response of the Ireland system frequency to supply/demand imbalances, as illustrated in Fig. 1. The system model was developed and is simulated using Matlab/Simulink. This model has been extensively validated for up to 20 s following a frequency excursion with historical data over many years, and full details are available in [20] [24]. The fixed-speed WTG [12] and DFIG WTG [10] models were incorporated into the system model. Simulated system frequency is used as input to generator and load models and is calculated in the connecting system (see Fig. 1) by the integration of the power imbalance [21], [25]. At nominal frequency, each generator model is in steady state, and power output is constant. When a power imbalance occurs, a frequency deviation from nominal results. A response from each generator, dependant on the steady-state set point, droop setting, and inertial characteristics, is modeled. D. Scenarios The predicted Ireland electricity system of 2010 is examined in this paper to investigate the impact of increasing wind capacity on frequency control. The validated system model

4 1908 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 20, NO. 4, NOVEMBER 2005 SNV case, the frequency response may be significantly different as the SNV case has substantial static reserve response. The range of wind penetration levels from 0 to 2000 MW was examined for each scenario. Due to insufficient wind generation data in existence for the Ireland system, analysis of the likelihood of different wind generation levels coinciding with the three scenarios above was not possible. Therefore, no assumption about the coincidence of any particular wind penetration with different load levels is made. Fig. 1. Schematic of system model. Details of individual models may be found in [10], [12], and [20] [24]. [20] [24] has been extended to take into account new generating plant coming onto the system [15], [16], [26]. The system load is increased in line with predicted values. The sources of generation in the predicted 2010 electricity system are assumed to be similar to the current system, although a number of older thermal units will be decommissioned, and all new generation connected to the system, with the exception of wind generation, will be either combined cycle gas turbines or open cycle gas turbines. Transmission effects are neglected in this paper, as it is assumed that the transmission system will be adequately enhanced for additional conventional generating plant and wind generation connecting to the system. It is also assumed that by 2010, an additional HVDC interconnector with a 500 MW capacity will link the Ireland system to Wales and that both this interconnector and the current HVDC interconnector with Scotland will be capable of providing limited frequency response [27] of up to 50 MW. When available, it is modeled as static reserve, which is triggered when the frequency reaches 49.5 Hz. For 2010, it is assumed that the largest infeed and the POR remain at 422 MW and 317 MW, respectively. The system is examined for increasing installed wind capacities under three different scenarios. These scenarios are carefully chosen to represent the most extreme situations that could occur on the Ireland electricity system. 1) Winter Peak (WP): This is the predicted peak load that will occur in 2010 on the system and occurs during a winter business day. In order to meet this peak load, a substantial amount of generating plant on the system is online, and system inertia is near maximum. Therefore, from an inertial response perspective, this case represents a best-case scenario. 2) Summer Night Valley (SNV): This is the predicted minimum load on the Ireland system in 2010 and occurs during a summer night. System inertia is very low at this point, and from an inertial response perspective, this case represents a worstcase scenario. 3) Summer Day Valley (SDV): This represents the expected minimum daytime load, which occurs during a summer nonbusiness day. While the system inertia is not as low as in the E. Simulating Procedure A merit order dispatch is employed in the system model, determined using historical dispatch data and forecast dispatches for future years [26]. Initially, the system model is in steady state, with generation and load balanced, and frequency constant at 50 Hz. At time, the largest infeed to the system model, a 422-MW generator, is tripped, resulting in a power imbalance. System frequency and the resultant response of each generator are simulated for 15 s subsequent to the tripping. For each scenario outlined in Section V-D, the impact of this disturbance on the system frequency for increasing wind penetration and for different wind turbine technologies is examined. It is assumed that the capacity of wind generation on the system displaces an equivalent amount of conventional generation and that this wind generation is not constrained downward to provide governor response. The conventional generation providing POR within each scenario remains the same regardless of wind penetration. V. RESULTS AND DISCUSSION A. Response of Wind Turbine Technologies to System Frequency Deviations The simulated system frequency trace resulting from the loss of the largest infeed during the WP scenario is illustrated in Fig. 2(i). The frequency falls to Hz, reaching the nadir or minimum frequency approximately 3.5 s after the start of the event. The inertial responses of a conventional synchronous generator with locked governor (purely the inertial response), an induction machine-based fixed-speed wind turbine generator, and a DFIG-based wind turbine generator to this frequency event are shown in Fig. 2(ii) and summarized in Table I. The inertial constant of the synchronous generator is taken to be 4.2 s, in comparison with 3.5 s [8] for the fixed-speed WTG inertial constant, since conventional synchronous generators generally have higher inertial constants than WTGs. It can be seen that the conventional synchronous generator produces the maximum inertial response in the shortest time. The response of the induction machine-based fixed-speed wind turbines is slower and lower, due to the reduced coupling of induction generator rotational speed to system speed compared with the synchronous generator and the smaller inertial constant. The assumption of either constant torque or constant power has a small impact on the maximum inertial response, with models assuming constant power producing a larger response. The DFIG WTGs show negligible inertial response, for both constant power and constant

5 LALOR et al.: FREQUENCY CONTROL AND WIND TURBINE TECHNOLOGIES 1909 Fig. 2. (i) Simulated system frequency resulting from the loss of the largest infeed during WP. (ii) Comparison of fixed speed WTG and DFIG responses to the low-frequency event in (i): Change in power output (%) of (a) a synchronous machine with inertial constant of H=4:2 s, (b) the fixed-speed WTG, assuming constant power, (c) the fixed-speed WTG, assuming constant torque, and (d) the DFIG, for constant power and constant torque. Fig. 3. Effect of increasing wind penetration (100% DFIG) on maximum rate of change of frequency following the loss of the largest infeed (422 MW) during the (a) WP scenario, (b) SNV scenario, and (c) SDV scenario. TABLE I COMPARISON OF INERTIAL RESPONSE FROM VARIOUS GENERATORS torque, as the DFIG controllers effectively decouple the generator rotational speed from the system speed [10]. From a system frequency control perspective, the constant torque assumption is the slightly more pessimistic approach and was therefore assumed in the subsequent results (see Sections VI-B and VI-C). B. System Frequency Control With Increasing Wind Penetration The impact of increasing proportions of wind generation on the system frequency during a variety of low-frequency events was examined. Proportions of DFIG versus fixed-speed wind turbines ranging from 0% to 100% were examined to represent numerous possibilities of installed wind capacity in The loss of the largest infeed (422 MW) during the 2010 winter peak, summer night valley, and summer day valley were simulated. It should be noted that the probability of a generation trip coinciding with such extreme conditions is very unlikely but possible and the general operating point of the system lies between these extremes. The important characteristics of the observed system frequency responses, namely, maximum ROCOF and frequency nadir (minimum frequency), are summarized in Table II and Figs Fig. 4. Simulated system frequency following the trip of largest infeed (422 MW) during the SDV scenario with (a) no wind generation, (b) 2000-MW fixed-speed WTGs, and (c) 2000-MW DFIG WTGs. As increasing amounts of installed wind generators displace conventional generation, regardless of whether DFIG WTGs with negligible inertial response or fixed-speed WTGs with slow inertial response, the net effect is a reduction of system inertial response. This results in increased rates of change of frequency during frequency transients. It can be seen from Table II that maximum ROCOF is sensitive to the amount of installed wind. Table II also illustrates that the type of wind turbine technology installed has little influence on the maximum ROCOF. Fig. 3, demonstrating the 100% DFIG case, further illustrates the increase in maximum ROCOF with increasing wind penetration. It should be noted that identical responses to those shown in Fig. 3 will be observed for any of the proportions of fixed speed to DFIG wind turbines listed in Table II. Considering that the ROCOF protection setting for generators connected to the Ireland electricity system is 0.5 Hz/s, it can

6 1910 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 20, NO. 4, NOVEMBER 2005 TABLE II MAXIMUM ROCOF FOLLOWING LOSS OF LARGEST INFEED (422 MW) FOR VARIOUS OPERATING SCENARIOS, WIND TURBINE PENETRATIONS, AND WIND TURBINE TECHNOLOGY TYPES Fig. 5. Frequency nadir (hertz) and static reserve tripped (megawatts) following the loss of the largest infeed (422 MW) for increasing wind penetration during the SDV scenario, where (a) frequency nadir for 100% fixed-speed WTG case, (b) frequency nadir for 100% DFIG WTG case, and (c) static reserve tripped (for both cases). Fig. 6. Frequency nadir (hertz) and static reserve tripped (megawatts) following the loss of the largest infeed (422 MW) for increasing wind penetration during the SNV scenario, where (a) frequency nadir for 100% fixed-speed WTG case, (b) frequency nadir for 100% DFIG WTG case, (c) static reserve tripped for 100% fixed-speed WTG case, and (d) static reserve tripped for 100% DFIG WTG case. be seen from Fig. 3 that these protection settings would not be exceeded for the winter peak scenario. This is due to the large amount of conventional generation online. For the summer night and summer day valley scenarios, protection settings would be exceeded at penetrations of wind of approximately 140 and 700 MW, respectively. Above these penetrations, there is a possibility that additional generation will trip, exacerbating the initial power imbalance that caused the low-frequency event. It should be noted here that the maximum ROCOF rates presented in Table II and Fig. 3 represent maximum simulated rates based on a filtered differentiation of the frequency signal. The detailed operation of ROCOF relays installed on the system would have to be known in order to determine if generation would trip for the scenarios examined [28]. In particular the time period over which the rate of change of frequency calculation is made would have to be examined in detail. Regardless of the operation of ROCOF relays, the general trend of increased rates of change of frequency will be observed as wind displaces conventional generation. While Table II illustrates that maximum ROCOF is independent of wind turbine technology, the frequency nadir is found to depend on the type of wind turbine technology. An example of the effect of WTG technology type on frequency nadir during the SDV scenario is depicted in Fig. 4, showing system frequency responses for no wind and each of 2000 MW of fixedspeed and DFIG wind generation. While the ROCOF is initially similar for both WTG types, the frequency nadirs reached differ substantially. The fixed-speed WTG case results in a frequency nadir reaching the same frequency level as for the no wind case, while the frequency nadir in the case of the DFIG WTGs is considerably lower. While Fig. 4 shows the frequency responses for a single penetration level of wind, the effect of increasing penetrations of both fixed-speed and DFIG WTGs on frequency nadir following the loss of the largest infeed (422 MW) is shown in Figs. 5 and 6. Both SDV (see Fig. 5) and SNV (see Fig. 6) scenarios are shown in order to examine the influence of increasing wind penetrations on static reserve usage. As outlined in Section V-D, the mix between static and dynamic reserve varies for SDV and SNV. During the SDV scenario, following the loss of the largest infeed, a constant amount of static reserve (50 MW) is tripped in all cases, so Fig. 5 primarily illustrates the differing effect on frequency nadir of the two WTG technology types. When fixed-speed WTGs comprise the wind generation, the frequency nadir rises by a small amount as wind penetration increases, due to the distinctive slower inertial response of the fixed-speed WTG. However, if DFIG WTGs comprise the wind generation, the frequency nadir falls further as wind penetration increases, due to the negligible response of the DFIG WTGs to changing system frequency. Thus, given constant capacity and dynamic/

7 LALOR et al.: FREQUENCY CONTROL AND WIND TURBINE TECHNOLOGIES 1911 Fig. 7. Supplementary control loop for DFIG WTG controller. static mix of POR, the frequency nadir is detrimentally affected if DFIG WTGs displace conventional generators and is largely unaffected if fixed-speed WTGs displace conventional generation. Both the influence of increasing wind penetrations on static reserve and the impact of static reserve on frequency nadir can be seen in Fig. 6. When fixed speed WTGs comprise the wind turbine generation, 123 MW of static reserve is tripped in all cases, and the frequency nadir does not fall below the 0 MW wind penetration case. However for DFIG WTGs, the tripping of an additional 73 MW of static reserve is required to prevent the frequency nadir from falling significantly below the 0 MW wind penetration case. As such, it may be concluded that increasing DFIG WTG penetration requires increasing availability of static reserve to maintain the frequency nadir above a given threshold. C. Supplementary Response From DFIG The magnitude of the inertial response of a DFIG depends on the extent by which the rotational speed changes in response to changing system frequency. As the DFIG is designed to provide accurate control of rotational speed, the coupling of rotational speed to system frequency and the resulting inertial response is largely removed [10]. However, through the addition of a simple supplementary loop to the controller of the DFIG, it is possible to configure the DFIG to change the electromagnetic torque in proportion to rate of change of frequency [14]. As a direct differentiation of measured system frequency is undesirable due to susceptibility to noise, the supplementary control loop torque is determined using the following (8), as illustrated in Fig. 7 Fig. 8. (i) Simulated system frequency resulting from the loss of the largest infeed during WP. (ii) Comparison of fixed-speed WTG and DFIG responses to the low-frequency event in (i): Change in power output (%) of (a) a synchronous machine with inertial constant of H=4:2 s, (b) the fixed-speed WTG, assuming constant power, (c) the fixed-speed WTG, assuming constant torque, (d) the DFIG with supplementary control loop included (K = 3:5), assuming constant power, and (e) the DFIG with supplementary control loop included (K =3:5), assuming constant torque. (8) The supplementary control loop torque is added to the reference torque of the DFIG WTG to provide the reference electromagnetic torque. This signal, in the same way as a natural inertial response, will impart energy to the system as frequency drops and absorb energy from the system as frequency increases, thus increasing the response of the DFIG above that which would be normally observed. The magnitude of the response will depend on the controller parameters (supplementary control loop constant and time constant ). The achievable inertial response of the DFIG WTG is limited by operational constraints such as current limits. In this paper, it is assumed the these limits are not exceeded. It must be noted that in practise, however, some design modifications may be required to prevent deviation outside operational constraints. A comparison of the inertial response during a frequency event from a synchronous generator, a fixed-speed WTG, and a DFIG WTG with the supplementary control loop included is illustrated in Fig. 8(ii). Instead of a negligible response to system Fig. 9. Simulated system frequency following the trip of largest infeed (422 MW) during the SDV scenario with (a) no wind generation, (b) 2000-MW fixed-speed WTGs, (c) 2000-MW DFIG WTGs, and (d) 2000-MW DFIG WTGs, with supplementary control loop added. frequency, as shown in Fig. 2(ii), the addition of the supplementary controller results in a DFIG response similar to the inertial response of the conventional generator. The size of the response is dependent on the value of parameter within the supplementary control loop, which was chosen to be 3.5 for this paper. The system frequency following the loss of the largest infeed during the SDV scenario is illustrated in Fig. 9. This figure is similar to Fig. 4 but includes 2000 MW of DFIG WTGs with supplementary control. The addition of the supplementary control loop to the DFIG WTG results in an improvement in system frequency response, both in terms of the rate of decline of the frequency and the maximum frequency excursion that occurs, as indicated in Fig. 9. However, these effects depend on both

8 1912 IEEE TRANSACTIONS ON POWER SYSTEMS, VOL. 20, NO. 4, NOVEMBER 2005 the value of the constant and the time constant within the controller. While these results indicate that the addition of the supplementary control loop to the DFIG WTG can potentially be beneficial to system frequency response, the ease of integration into the current technology is not assessed here. VI. CONCLUSION As a consequence of differing inertial response characteristics, rates of change of system frequency will increase as wind generation displaces conventional generation. The maximum rate of change of frequency following a loss of generation is independent of wind turbine technology. As fixed-speed wind turbines displace conventional synchronous generation, there is no significant change in minimum frequency reached following a loss of generation. This is due to the inertial response provided by fixed-speed wind turbines. As DFIG wind turbines displace conventional synchronous generation, the frequency nadir following a loss of generation reduces. This is due to the negligible inertial response provided by DFIG wind turbines. To allow for increased penetration of wind, a change in reserve policy may be required. For example, increasing DFIG wind turbine usage may necessitate additional availability of static reserve to maintain system frequency above a given threshold. This is particularly important for small power systems where system inertia is low. A possible solution to the lack of DFIG wind turbine inertial response is through the addition of a supplementary control loop to provide an inertial response similar to a conventional synchronous generator. The achievable inertial response of a standard DFIG WTG is limited by operational constraints, such as current limits. In this paper, it was assumed that these limits were not exceeded. In practice, the implementation of the supplementary control loop and the maintenance of operational constraints within required limits may be problematic and some design modification, such as an increase of DFIG converter rating, may be required. ACKNOWLEDGMENT The authors gratefully acknowledge the useful discussions and interactions with colleagues in Electricity Supply Board National Grid (ESBNG), Northern Ireland Electricity (NIE), The Queen s University of Belfast (QUB), and the Electricity Research Centre (ERC) in University College Dublin (UCD). REFERENCES [1] The United Nations Framework Convention on Climate Change. (1997) The Kyoto Protocol. [Online]. Available: [2] Directive 2001/77/EC of the European Parliament and the Council of 27 September 2001 on the promotion of electricity produced from renewable energy sources in the internal electricity market, Official J. Eur. 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9 LALOR et al.: FREQUENCY CONTROL AND WIND TURBINE TECHNOLOGIES 1913 Gillian Lalor (S 03) received the B.E. degree in mechanical engineering from University College Dublin, Dublin, Ireland, in She is currently working toward the Ph.D. degree at University College Dublin. Her research interests are in power system modeling and control. Mark O Malley (S 86 M 87 SM 96) received the B.E. and Ph.D. degrees from University College Dublin, Dublin, Ireland, in 1983 and 1987, respectively. He is currently a Professor at University College Dublin and the Director of the Electricity Research Centre, with research interests in power systems, control theory, and biomedical engineering. Alan Mullane (S 01 M 03) received the B.E. degree in electrical and electronic engineering in 1998 and the Ph.D. degree in electrical engineering in 2003, both from the Department of Electrical and Electronic Engineering, University College Cork, Cork, Ireland. In 2004, he joined the Electricity Research Centre, University College Dublin, Dublin, Ireland, as a Postdoctoral Research Fellow. His research interests include nonlinear modeling and control of dynamic systems, with particular interest in simulation and control of wind turbines and their integration into electrical networks.