*1.4.1. Inertial response*

With the increasing penetration of inverter-based generation technologies, such as modern wind plants, the primary frequency response of several North American and European grids has been declining for years. The concern is most pronounced during simultaneous light load and high wind, where economics dictates that fewer synchronous generators will be operating, and the overall grid inertia will consequently be reduced.

This was confirmed by a study performed in late 2010 by the Lawrence Berkeley National Lab and sponsored by the Federal Energy Regulatory Commission (FERC) in USA. The ob‐ jective of the study was to examine the status of the American grids with respect to frequen‐ cy regulation capabilities [38]. Among other results, the study concluded that:


It was thus concluded that the approach for maintaining adequate frequency responsive re‐ serves should not involve only new requirements for wind generation, but also innovative solutions on the demand side and improvements in the frequency response of the existing conventional generation.

In another case, the integration of wind energy in Québec has triggered an added need for frequency support in order to avoid reaching the low-shedding thresholds under critical generation loss scenarios. The power system of Québec is connected to its neighboring sys‐ tems asynchronously, thus it is responsible for its own frequency regulation as an independ‐ ent region of the North American Electric Reliability Corporation (NERC). With the current inertia of Québec's system, large post-contingency frequency excursions up to ±1.5 Hz for extended periods can potentially occur. In a recent study [30], HQTE concluded that if 2000MW of hydro generation is replaced by wind turbine generators without inertial re‐ sponse, the frequency nadir will deteriorate by about 0.2 Hz within the first 10 seconds. As a result, HQTE requires wind plants to be equipped with an inertia emulation system to sup‐ port system frequency following a major frequency event [23]:


The requirement can be satisfied if the active power is increased rapidly by 5% for about 10 sec following a major frequency deviation. A similar provision is stipulated by the Inde‐ pendent Electric System Operator (IESO) of Ontario.

Similar investigations are carried out in Europe. A study by the Irish grid operator forecasts deficiencies in system performance in terms of frequency and voltage control due to the in‐ creasing share of non-synchronous generation by 2020 [27]. The analysis concluded that:


The solutions that involve the replacement of the RoCoF relays on the distribution networks with alternative protection schemes or increasing the RoCoF thresholds. New commercial mechanisms and financial models are also being studied to allow for advanced ancillary services.

In the UK, the system operator performed a technical assessment of the available options for the management of frequency response with the integration of wind power [22]. The recom‐ mendations called for:


In recognition of the grid's need for frequency response, wind turbine manufacturers have developed control functions that temporarily increase power output when frequen‐ cy declines by withdrawing energy from the rotating inertia of the turbine. [39]-[46] con‐ tain descriptions of several implementations sought in the industry (and in research) with and without auxiliary storage. [47] provides a comprehensive summary and comparison of the different implementations to date. A common aspect among all these implementa‐ tions, irrespective of the wind turbine generator (WTG) topology or electric concept, is that the amount of power boost is not constant but rather a function of the wind condi‐ tion. This is because all modern WTGs are variable-speed machines that regulate their ro‐ tational speed to optimize power capture from the wind. Another feature is the recovery period that follows the power boost when the WTG is operating at below-rated condi‐ tions. During the recovery period, the WTG withdraws active power from the grid to re‐ cover its pre-event rotational speed. The design considerations for inertial response emulation include: (a) the optimal amount of power that can be drawn from the rotating masses; (b) the duration of the momentary injection; and (c) the duration of the speed and energy recovery phase.

A long-term overproduction is more challenging for WTGs. Since they are designed to cap‐ ture the maximum amount of power from the wind at any given moment, it is not possible to maintain an increase in the output power. Leaving "headroom" to increase production would necessitate spilling wind energy when wind speeds are below the turbine's rating, thereby incurring an economic penalty due to reduced annual production levels. The utiliza‐ tion of such a capability therefore comes down to economics, i.e., the value of primary fre‐ quency response relative to the value of the wind energy. This technical option is discussed in the following section in the context of the British frequency control requirements.

#### *1.4.2. Primary reserve for under-frequency*

generation loss scenarios. The power system of Québec is connected to its neighboring sys‐ tems asynchronously, thus it is responsible for its own frequency regulation as an independ‐ ent region of the North American Electric Reliability Corporation (NERC). With the current inertia of Québec's system, large post-contingency frequency excursions up to ±1.5 Hz for extended periods can potentially occur. In a recent study [30], HQTE concluded that if 2000MW of hydro generation is replaced by wind turbine generators without inertial re‐ sponse, the frequency nadir will deteriorate by about 0.2 Hz within the first 10 seconds. As a result, HQTE requires wind plants to be equipped with an inertia emulation system to sup‐

**•** The performance should be at least as much as that of a conventional synchronous gener‐

The requirement can be satisfied if the active power is increased rapidly by 5% for about 10 sec following a major frequency deviation. A similar provision is stipulated by the Inde‐

Similar investigations are carried out in Europe. A study by the Irish grid operator forecasts deficiencies in system performance in terms of frequency and voltage control due to the in‐ creasing share of non-synchronous generation by 2020 [27]. The analysis concluded that:

**•** The projected levels of synchronous inertia available in 2020 will be less than the amount

**•** At high instantaneous non-synchronous generation, there is a risk of excessive activation of Rate of Change of Frequency (RoCoF) protection relays that shut down wind turbines

The solutions that involve the replacement of the RoCoF relays on the distribution networks with alternative protection schemes or increasing the RoCoF thresholds. New commercial mechanisms and financial models are also being studied to allow for advanced ancillary

In the UK, the system operator performed a technical assessment of the available options for the management of frequency response with the integration of wind power [22]. The recom‐

**•** A faster frequency response capability in the first 5 seconds following a load-generation

**•** A closer examination of the sensitivity of the frequency response with respect to the

In recognition of the grid's need for frequency response, wind turbine manufacturers have developed control functions that temporarily increase power output when frequen‐

**•** A clearer rephrasing of the grid code provisions addressing frequency control

port system frequency following a major frequency event [23]:

ator whose inertia constant (H) equals 3.5 sec.

pendent Electric System Operator (IESO) of Ontario.

needed to meet the statutory system requirements

ramping capability of the existing generation

**•** A reexamination of the existing RoCoF settings.

under certain scenarios.

mendations called for:

mismatch

services.

346 Advances in Wind Power

**•** The system should respond to major frequency deviations only

The British grid code contains the most advanced (and complex) frequency control require‐ ments to date. Several operation modes are asked from wind plants whose installed capacity is beyond 50 MW depending on the actual value of the system frequency relative to the sys‐ tem Target Frequency (50 ± 0.1 Hz.

The system operator will send to the wind plant a signal with the Target Frequency and an instruction of whether to operate in the Frequency Sensitive Mode (FSM) or Limited Fre‐ quency Sensitive Mode (LFSM). If FSM is specified, the control system has to automatically regulate the active power output as a function of the deviation of the actual frequency from the target frequency, in a direction assisting in the recovery to the target frequency.

When the system operator expects an under-frequency situation, the wind plant is curtailed prior to the frequency drop via a separate command from the system operator. When the frequency drops below the target frequency, the wind plant must exhibit a Primary (P) and Secondary (S) response as defined in Figure 7. The new active power set point can be ob‐ tained from Figure 7 for a 0.5 Hz deviation. For smaller deviations, the response should be at least proportional to the requirement specified for the 0.5 Hz deviation [21].

**Figure 7.** a) Minimum frequency response requirement for 0.5Hz frequency change from target frequency. (b) Inter‐ pretation of Primary (P), Secondary (S), and High-Frequency response values [21].

If the LFSM operation mode is specified by the system operator, only an over-frequency re‐ sponse is required. The active power control system must withhold the output for frequen‐ cies in the range between the target frequency and 50.4 Hz. Beyond 50.4 Hz, it must be reduced at a rate of at least 2% of actual active power per 0.1 Hz. The response should last until the frequency drops again below 50.4 Hz, with as much as possible delivered within the first 10 sec from the rise [21].

#### *1.4.3. Over-frequency response*

Wind plants are commonly asked to limit their active power as a function of the system fre‐ quency in over-frequency situations. For example, wind plants in the Canadian province of Alberta are required to have an over-frequency control system that:


**•** has no intentional time delay, but may have a deadband of up to 36 mHz.

In Ireland, whose grid is known for its notorious frequency profile due to weak interconnec‐ tion with the neighboring systems, the grid code demands from wind plants to control ac‐ tive power as close to real-time as possible according to the response curve described in Figure 8. The rate of response should be 1% of rated power per second for each online WTG [26]. Similar requirements exist in other European grid codes.


**Figure 8.** Power-frequency response curve - Irish code [26]. WFPS: Wind farm power station.

#### **1.5. Reactive power & voltage regulation**

**Figure 7.** a) Minimum frequency response requirement for 0.5Hz frequency change from target frequency. (b) Inter‐

If the LFSM operation mode is specified by the system operator, only an over-frequency re‐ sponse is required. The active power control system must withhold the output for frequen‐ cies in the range between the target frequency and 50.4 Hz. Beyond 50.4 Hz, it must be reduced at a rate of at least 2% of actual active power per 0.1 Hz. The response should last until the frequency drops again below 50.4 Hz, with as much as possible delivered within

Wind plants are commonly asked to limit their active power as a function of the system fre‐ quency in over-frequency situations. For example, wind plants in the Canadian province of

**•** continuously monitors the grid frequency at a sample rate of 30/sec and a resolution of at

**•** automatically controls the active power in a manner proportional to the frequency in‐

**•** has control priority over the other power limiting control functions like ramp rate limita‐ tions and curtailment set-point, and must reduce the active power output for an over-fre‐

pretation of Primary (P), Secondary (S), and High-Frequency response values [21].

Alberta are required to have an over-frequency control system that:

crease by a factor of 33% per Hz of actual active power output

**•** responds at a rate of 5%/second of the actual active power output

quency condition even when these requirements are in effect

the first 10 sec from the rise [21].

*1.4.3. Over-frequency response*

least 4 mHz

348 Advances in Wind Power

Voltage regulation in a power system is directly related to the flow of reactive power and is dependent on the short circuit capacity and impedance of the network. Large and quick var‐ iations of wind output can cause transient disturbances of the system voltage and tie line flows, both of which can lead to voltage stability issues especially in congested transmission corridors [2].

Conventional generation facilities have traditionally provided reactive power to support system voltage. These facilities have synchronous machines capable of operating in power factor ranges of +/-0.90 or +/-0.95. Voltage regulators on their excitation systems provide the primary voltage control function [6]. Older wind plants have been interconnected without these capabilities; occasionally leading to problems such as depressed voltages, excessive voltage fluctuation, and inability to deliver full power [6].

#### *1.5.1. Steady-state reactive power range*

In addition to the capability of operating within an extended voltage bandwidth around unity, modern wind plants are required to offer advanced reactive power and voltage con‐ trol capabilities. The supplied reactive power should compensate for the reactive power loss and line charging inside the wind plant and up to the POI. It is often also required to regu‐ late the POI voltage using dynamic reactive power in-feed, either automatically or in re‐ sponse to real-time instructions from the operator.

According to the British grid code, wind power plants must be capable of operating continu‐ ously at any point in the ranges illustrated in Figure 9. They must also be capable of continu‐ ous operation between a power factor of 0.95 lag and 0.95 lead when supplying rated MW.

**Figure 9.** Minimum requirements for reactive power range - British code [21].

Figure 10 shows the reactive power and power factor ranges specified in the Irish code [26].

**Figure 10.** Requirements for reactive power capability of wind plants - Irish code [26].

Figure 11 shows the required static and dynamic reactive power ranges in the Canadian province of Alberta [19]. The requirement applies at the low-voltage side of the transmission step-up transformer. The dynamic capability is defined as the short-term reactive power re‐ sponse in a period of up to 1 second.

A supervisory control is normally present within a wind plant translating the reactive pow‐ er or voltage demands at the connection point to operational set points for the individual WTGs. In some implementations, identical set points are dispatched to all turbines to keep the design of the controller simple. In others, the set point is optimized for each individual turbine [6].

late the POI voltage using dynamic reactive power in-feed, either automatically or in re‐

According to the British grid code, wind power plants must be capable of operating continu‐ ously at any point in the ranges illustrated in Figure 9. They must also be capable of continu‐ ous operation between a power factor of 0.95 lag and 0.95 lead when supplying rated MW.

Figure 10 shows the reactive power and power factor ranges specified in the Irish code [26].

Figure 11 shows the required static and dynamic reactive power ranges in the Canadian province of Alberta [19]. The requirement applies at the low-voltage side of the transmission step-up transformer. The dynamic capability is defined as the short-term reactive power re‐

A supervisory control is normally present within a wind plant translating the reactive pow‐ er or voltage demands at the connection point to operational set points for the individual WTGs. In some implementations, identical set points are dispatched to all turbines to keep

sponse to real-time instructions from the operator.

350 Advances in Wind Power

**Figure 9.** Minimum requirements for reactive power range - British code [21].

**Figure 10.** Requirements for reactive power capability of wind plants - Irish code [26].

sponse in a period of up to 1 second.

**Figure 11.** Requirements for reactive power capability of wind plants - AESO code [19].

Power flow calculations are performed to assess if the reactive power capabilities of the WTGs are enough to comply with the steady-state requirements. Although the collector sys‐ tem design work may be considered a separate activity, some iteration will usually be re‐ quired. Transformers equipped with on-load tap changers are another system component that affects the voltage profile and reactive power flows. The speed of response of the tap changer, the size of the first step and those of subsequent steps are all relevant parameters that need to be optimized for a cost-efficient, grid code compliant wind plant-level control scheme.

Reactive power compensation equipment, such as static var compensators (SVCs) and static compensators (STATCOMs), may also help compliance with grid codes when there is little wind, or when the requirement is beyond the capability range of the WTGs. In offshore wind plants with lengthy submarine ac cables, high charging currents necessitate the injec‐ tion of a large amount of apparent power. This greatly reduces the reactive power supply and absorption margin at the on-shore POI under different operating conditions. Therefore, reactive power compensation elements are often needed in these cases at the high-voltage level.

#### *1.5.2. Voltage regulation & dynamic response*

Although the main focus is on the quasi-steady-state behavior of the wind plant, system op‐ erators also impose certain dynamic performance criteria. In general, there are three com‐ mon reactive power control modes for wind plants:


Voltage control is gaining more and more popularity, especially for large wind plants. For instance, wind plants in the UK connected to a line rated 33kV or above are required to con‐ tribute to voltage control with a predefined reactive power–voltage droop characteristic, as shown in Figure 12. If a sudden voltage change occurs in the grid, the wind plant is required to start reacting no later than 200 ms after the change and should provide at least 90% of the required reactive power within 1 second. After 2 seconds from the event, the oscillations in the reactive power output may be no larger than ±5% of the target value.

**Figure 12.** Voltage-reactive power envelope for voltage levels >33kV - British code [21].

The code of the Canadian province of Alberta requires from wind plants to have a continu‐ ously acting, closed-loop control voltage regulation system capable of responding to any voltage set-point sent by the system operator between 95% and 105% of rated voltage. The system must also be able to regulate voltage according to an adjustable droop from 0 to 10%. The dynamic response must be such that a change in reactive power will achieve 95% of its final value no sooner than 0.1 second and no later than 1 second following a step change in voltage [18]. Specific dynamic criteria such as these are becoming more common together with the droop characteristics and steady-state specifications.

#### **1.6. Voltage disturbance requirements**

Unsurprisingly, special emphasis is placed in grid codes on the ability of wind plants to sur‐ vive grid faults and contribute to supporting the grid during and after such events.

## *1.6.1. Fault ride-through*

and absorption margin at the on-shore POI under different operating conditions. Therefore, reactive power compensation elements are often needed in these cases at the high-voltage

Although the main focus is on the quasi-steady-state behavior of the wind plant, system op‐ erators also impose certain dynamic performance criteria. In general, there are three com‐

**1.** Fixed reactive power mode, in which a set point reactive power flow is maintained as

**2.** Fixed power factor mode, in which the ratio between active and reactive power is main‐ tained. This mode is common for small wind plants or those connected to the distribu‐

**3.** Voltage control mode, in which the wind plant contributes reactive power to regulate

Voltage control is gaining more and more popularity, especially for large wind plants. For instance, wind plants in the UK connected to a line rated 33kV or above are required to con‐ tribute to voltage control with a predefined reactive power–voltage droop characteristic, as shown in Figure 12. If a sudden voltage change occurs in the grid, the wind plant is required to start reacting no later than 200 ms after the change and should provide at least 90% of the required reactive power within 1 second. After 2 seconds from the event, the oscillations in

level.

352 Advances in Wind Power

*1.5.2. Voltage regulation & dynamic response*

specified by the system operator

mon reactive power control modes for wind plants:

tion system and operated as distributed generation (DG)

the reactive power output may be no larger than ±5% of the target value.

**Figure 12.** Voltage-reactive power envelope for voltage levels >33kV - British code [21].

The code of the Canadian province of Alberta requires from wind plants to have a continu‐ ously acting, closed-loop control voltage regulation system capable of responding to any

the voltage magnitude at the connection point.

Although fault ride-through (FRT) profiles for WTGs were introduced more than 15 years ago, the discussions on how they should be established, interpreted and applied in practice are still hot. Early FRT requirements were mere adaptations from those of conventional gen‐ erators and consisted of specifications of minimum connection durations as a function of voltage drop/rise magnitude. Contemporary provisions evolved to different levels of com‐ plexity and degrees of flexibility.

Figure 13 shows the FRT requirements in Québec [23]. Wind power plantss are also required to remain in service up to 0.15 seconds for double-phase-to-ground faults and 0.30 seconds for single-phase-to-ground faults.

**Figure 13.** FRT capability required from wind plants - HQTE code [23]; 1 Positive-sequence voltage on HV side of switchyard; 2 Up to hours, depending on time needed to bring grid voltage back to steady-state range; 3 Temporary blocking is allowed beyond 1.25p.u. but normal operation must resume once voltage drops back below 1.25p.u.

Figure 14 shows the FRT curve of one for the German codes [16]. Wind power plants must remain connected without instability above limit line 1 for all symmetrical or unsymmetrical voltage dips. Voltage drops within the area between limit lines 1 and 2 should not lead to disconnection, but short-time disconnection is allowed case of WTG instability. Disconnec‐ tion is allowed below limit line 2.

**Figure 14.** Low-voltage ride-through requirements for wind plants - German code [16].

The Australian grid code stipulates that wind plants must be capable of continuous uninter‐ rupted operation in voltage transients caused by high speed auto-reclosing of transmission lines, irrespective of whether or not a fault is cleared during a reclosing sequence. Thus the wind power plant must be capable of riding through multiple faults as shown in Figure 15, which might be difficult for some FRT implementations due to excess stress on the drivetrain of the WTG.

**Figure 15.** Low-voltage ride-through capability during auto-reclose operation - Western Power [27].

#### *1.6.2. In-fault and post-fault requirements*

In addition to remaining connected through the fault, some FRT provisions contain specifi‐ cations for reactive current in-feed during the fault as well as precise criteria for active pow‐ er recovery once the fault is cleared.

One German code [16] requires wind plants to support the grid voltage with additional re‐ active current in proportion to the voltage deviation, as shown in Figure 16. The in-feed must start within 20 msec of the occurrence of the voltage dip and must be maintained for a further 500 milliseconds after the voltage returns to the 10% voltage dead band. Resynchro‐ nization must take place within up to 2 sec and active power must increase with a rate not less than 10% of rated power after fault clearance.

**Figure 16.** Required voltage support during disturbances in onshore wind plants - German codes [16].

**Figure 14.** Low-voltage ride-through requirements for wind plants - German code [16].

**Figure 15.** Low-voltage ride-through capability during auto-reclose operation - Western Power [27].

In addition to remaining connected through the fault, some FRT provisions contain specifi‐ cations for reactive current in-feed during the fault as well as precise criteria for active pow‐

One German code [16] requires wind plants to support the grid voltage with additional re‐ active current in proportion to the voltage deviation, as shown in Figure 16. The in-feed must start within 20 msec of the occurrence of the voltage dip and must be maintained for a

train of the WTG.

354 Advances in Wind Power

*1.6.2. In-fault and post-fault requirements*

er recovery once the fault is cleared.

The Australian grid code stipulates that wind plants must be capable of continuous uninter‐ rupted operation in voltage transients caused by high speed auto-reclosing of transmission lines, irrespective of whether or not a fault is cleared during a reclosing sequence. Thus the wind power plant must be capable of riding through multiple faults as shown in Figure 15, which might be difficult for some FRT implementations due to excess stress on the drive-

> Grid codes of UK and Ireland code [21] requires offshore wind power plants to provide ac‐ tive power output during voltage dips at least in proportion to the retained balanced voltage [26]. The Spanish code [25] has requirements for both active and reactive power consump‐ tion during a fault. Wind plants are not allowed to absorb active power during a balanced 3 phase fault or during the voltage recovery period after clearance. Absorption of active and reactive power is accepted for 150 msec interval after the beginning of the fault and 150 msec after clearance, as shown in Figure 17 (a). During the rest of the fault time, active pow‐ er consumptions must be limited to 10% of the plant rated power. Within the 150 msec, the reactive power injection should be controlled as shown in Figure 17 (b).

> Implementing the low-voltage ride-through in WTGs implies a proper management of the power being converted by the machine in the absence of the load or power sink provided by the grid [33]. This power needs to be curtailed, dissipated or stored, to avoid generator overspeeding. A number of technical possibilities are available: (a) acting on the blade capture rate by changing, for example, the blade angles, thus reducing the amount of wind power captured; (b) acting on the generator so that it no longer produces power and that the power does not flow from the stator into the grid; (c) dissipating the power produced by the gener‐ ator, by means of resistances on the dc bus or using storage devices (seldom implemented). A combination of these solutions can be used concurrently.

**Figure 17.** Active power under balanced 3-phase faults - Spanish code [24].

#### **1.7. Harmonic emissions of wind power plants**

The influence of a wind power plant on the current/voltage harmonic distortion should be considered in the design process since all system operators have maximum allowed emis‐ sion levels for single order and total harmonic distortion at the connection point. The three sources contributing to the harmonic levels in a wind power plant are [8]:


The contribution of each of these four sources to the total harmonic voltage distortion can be determined separately but should not be added arithmetically because they are not in phase. Therefore, summation laws, such as those of the IEC 61400-21 standard, can be applied for a more realistic account for angular differences and randomness of the harmonics.

Reactive power compensation elements will also affect the harmonic performance. SVCs and STATCOMs inject harmonics into the grid just as the wind turbines do. The collector system cables can also act as amplifiers for the harmonic emissions, especially in offshore wind power plants. The long ac submarine cables have frequency characteristics that could trigger critical resonances with the power system at relatively low frequencies.

Adequate modeling of the grid impedance as seen from the wind plant is also very impor‐ tant to quantify the grid's contribution to the harmonic emissions. The grid's impedance is not static; it's rather a function of the switching state and loading level in the grid. The dom‐ inant approach is to obtain (through simulation) the network impedance for a wind range of system states and plot them as a set of impedance loci in the complex impedance (*R*–*X*) plane. An example of this plot is given in Figure 18. For each harmonic frequency corre‐ sponds an *R*–*X* plane, where the points *p <sup>1</sup>* through *p <sup>4</sup>* are usually fixed whereas *Z max* is dif‐ ferent for each harmonic order.

**Figure 18.** Typical impedance plane as provided by network operators.

The wind plant's contribution to the harmonic voltage distortion at the POI has to be deter‐ mined by assuming the worst-case network impedance in terms of resonances, which is gen‐ erally different from the value resulting in the highest wind turbine contribution. If the harmonic performance analysis indicates that emission limits are likely to be exceeded, miti‐ gation measures must be carried out. In order to mitigate the problem at the WTG level, some vendors equip their turbines with specific control schemes whose objective is to dis‐ place the phase angle between turbines to minimize the distortion at the connection point. At the wind plant level, one or more filters can typically be added to the design to diminish the emission at the most critical harmonic frequencies.

### **1.8. Other interconnection concerns**

#### *1.8.1. Power system stabilizers*

(a) (b)

The influence of a wind power plant on the current/voltage harmonic distortion should be considered in the design process since all system operators have maximum allowed emis‐ sion levels for single order and total harmonic distortion at the connection point. The three

The contribution of each of these four sources to the total harmonic voltage distortion can be determined separately but should not be added arithmetically because they are not in phase. Therefore, summation laws, such as those of the IEC 61400-21 standard, can be applied for a

Reactive power compensation elements will also affect the harmonic performance. SVCs and STATCOMs inject harmonics into the grid just as the wind turbines do. The collector system cables can also act as amplifiers for the harmonic emissions, especially in offshore wind power plants. The long ac submarine cables have frequency characteristics that could

Adequate modeling of the grid impedance as seen from the wind plant is also very impor‐ tant to quantify the grid's contribution to the harmonic emissions. The grid's impedance is not static; it's rather a function of the switching state and loading level in the grid. The dom‐ inant approach is to obtain (through simulation) the network impedance for a wind range of system states and plot them as a set of impedance loci in the complex impedance (*R*–*X*) plane. An example of this plot is given in Figure 18. For each harmonic frequency corre‐ sponds an *R*–*X* plane, where the points *p <sup>1</sup>* through *p <sup>4</sup>* are usually fixed whereas *Z max* is dif‐

more realistic account for angular differences and randomness of the harmonics.

trigger critical resonances with the power system at relatively low frequencies.

**Figure 17.** Active power under balanced 3-phase faults - Spanish code [24].

sources contributing to the harmonic levels in a wind power plant are [8]:

**2.** the dynamic reactive power compensation equipment (if any)

**1.7. Harmonic emissions of wind power plants**

**1.** the wind turbine generators

**4.** the electric grid itself

356 Advances in Wind Power

ferent for each harmonic order.

**3.** the collector system feeders, and

Some of the recent grid codes include references to the capability of wind power plants in contributing to power oscillation damping in the grid through power system stabilizers (PSS). The grid code of HQTE, for example, stipulates that wind plants must be designed and built so that they can be equipped with a stabilizer in case it was imposed later during the lifetime of the wind power plant.

In synchronous generators, PSSs are used to damp oscillations arising from interactions be‐ tween generators in a power plant, generators and the network and between generation areas. These functions are implemented using a supplementary control loop acting on the generator excitation system or voltage regulator. Damping is achieved through modulation of the reactive power produced by the generator. Modulating the real power flow through the governor would be slow with cost impacts on the turbine design and performance. However this is easier with wind power plants. The active and reactive power can be modu‐ lated independently by means of two separate supplementary control loops on the power converter regulator [48]-[50]. In the case of a DFIG, the control of higher frequency oscilla‐ tions is limited by the rating of the rotor side converter, however, in the case of full convert‐ ers, the control range can be significantly wider and the control can be made more effective.

There are options for implementing and triggering PSS functions in wind plants. One of them is based on the frequency deviation. Studies were carried out to demonstrate that both active and reactive power control could be used effectively to damp inter-machine oscilla‐ tions and to investigate the impact of the wind plant location on the damping effectiveness [33], [48]. It was found that, in general, active power control is less dependent on location, but still more effective when the point of POI of the wind plant was located close to a syn‐ chronous generator plant.
