Inertial Response and Frequency Control Requirements

3.2 Conceptual Discussion and Background

The steadily increasing penetration of wind in various power system grids has at­tracted a lot of attention on the ability of various wind turbine technologies to pro­vide dynamic reactive power and/or voltage support. The increased penetration of wind has also resulted in displacement and/or de-commitment of conventional generation resources thereby reducing the grid inertia derived from them. In such situations, the ability of wind turbine technologies to provide primary frequency control and/or inertial response capabilities is of prime significance.

Frequency response is defined as the automatic corrective response in order to balance demand and supply. The frequency response of a typical power system can be broadly classified into 3 categories based on the response time namely:

• Inertial Frequency Response: This category of frequency response is inherently present in the system due to the rotating masses in the sys­tem typically comprising of conventional synchronous generation and motor loads. The Inertial Frequency Response typically responds to system disturbances within seconds of the disturbance initiation to ar­rest the frequency deviation.

• Primary Frequency Response (PFR): This category of frequency re­sponse can be defined as the increase and/or decrease in active power output in proportion to the system frequency deviations. This type of response typically derived from synchronous generation units acting on primary governor response. The timeframe associated with the pri­mary frequency response is typically within 12 to 14 seconds. Howev­er, in case of a system disturbance all governor units will respond to the deviation based on the governor droop characteristics. While this action reduces the frequency deviation, supplemental control is neces­sary to adjust the load reference set-point thereby restoring the steady state frequency to its nominal value.

• Secondary Frequency Response: This category of frequency response corresponds to Automatic Generation Control (AGC) action typically deployed to regulate the frequency back to 60Hz after the deployment of the PFR. The objective of AGC, apart from restoring the frequency to its nominal value, is to ensure the maintenance of power transfer be­tween control areas at scheduled values by adjusting the output of se­lect generation units.

The increasing penetration of WGR on the power system grid has come at the cost of displacing conventional synchronous generation from the “order -of – merit” stack. The economic benefits of this displacement have been vastly quantified in terms of reduced over-all production costs and increased cost savings owing to the lower price wind generation. However, the price that system operators and utilities tend to pay for this displacement in terms of lost system inertia has rarely if ever
quantified until recently. The impact of the reduced system inertia is more exagge­rated due to the coincidence of high wind penetration periods on the power system network with light load conditions. Due to high wind availability during light load conditions, the system inertia under such conditions is at its minimum. The wind generation resources cannot provide near as much inertia to the system due to the decoupling of the machines from the system by power electronic devices. This situation is obviously more exacerbated in case of Type III and Type IV turbines.


—— * f0 +———

2H 0 2H

Подпись: df dt Подпись: *Af Подпись: (10)

Inertial Frequency Response is defined as “The power delivered by the Inter­connection in response to any change in frequency due to the rotating mass of ma­chines synchronously connected to the Bulk Power System (BPS), including both – load and generation” [3]. System frequency drops whenever there is shortage of generation to supply demand and frequency increases whenever there is excess of energy. Sudden loss of supply or demand will result in frequency deviation from the nominal frequency. The rate of change in frequency due to imbalance depends on the system inertia. System inertia is directly proportional to synchronously ro­tating mass in the system (includes synchronous generation and motor load). The general equation for calculating rate of change of frequency using system inertia constant (H) is illustrated by:


H: system inertia constant on system base (s)

D: Load Damping Constant (pu/Hz)

f0: frequency at the time of disturbance (Hz)

df/dt: Rate of Change of Frequency (Hz/sec)

AP: Power Change Af: Change in frequency

As is obvious from the discussion presented above, the inertial response and fre­quency control requirements and assessments associated with WGRs is gaining significance across various power system networks. Utilities and/or regional relia­bility organizations have placed increased stress on WGR’s ability to provide frequency control as part of the interconnecting and grid integration process. The ensuing sub-sections under this section present a qualitative and quantitative as­sessment of frequency control and inertial response capabilities associated with various turbine types with special focus on DFIG frequency control capabilities.

R(per unit), the slope of the “droop” curve, is defined as Af(p. u.)/ AP(p. u.)


Af(p. u.)= Af(HZ) / 60.0 AP(p. u.)= AP(MW) / Unit Capacity

In order to understand the concept of a 5% droop characteristic, the following illu­stration is presented:

For a 600 MW unit that has a governor response of 20 MW for a frequency ex­cursion that settles out at 59.9 HZ:

R=Af(p. u.)/AP(p. u.) = (0.1/60)/(20/600) =0.05 or 5% droop

In other words, once the droop is known, the MW response to frequency deviation can be determined by:

(AP/Af)=(1/R), or AP=(1/R) X Af

Taking the aforementioned illustration, for the 600 MW unit with 5% droop:

(AP/600)=(1/0.05) X (Af/60), or AP=200MW/HZ

Figure 20 depicts the graphic illustration of a droop characteristic described above:

Inertial Response and Frequency Control Requirements

Fig. 20 Typical Steady State Droop Curve Characteristic

The same concept can then be extended to a system containing more than one generator with varying governor droop characteristics. For example, Table 2 de­picts a system with 3 generators and associated capacities and droop characteristics.

Table 2 Sample System with 3 Generators – Capacity & Droop Characteristics







80 MW


0.100 (10%)



120 MW


0.075 (7.5%)



160 MW


0.050 (5%)


Following the addition of 21 MW of load on the aforementioned system, the re­sulting steady state frequency and amount picked up by each generator can be simply calculated as:

• Steady State Frequency

Unit #1: AP1=50 X Af Unit #2: AP2=100 X Af Unit #3: AP3=200 X Af A£Pi=350Af=21MW,



• MW Amount picked up by each generator

AP1=50 X 0.06=3MW AP2=100 X 0.06=6MW AP3=200 X 0.06=12MW Check: A£Pi=21MW

The aforementioned illustration also underlines the fact that governor response alone cannot restore the system frequency back to nominal in the absence of sup­plemental control in the form of AGC.

To that effect, generator droop curve, ranges of frequency and/or active power output and the dead-band region are all key aspects in assessing the need and ex­tent of primary frequency response associated with a generator.

Updated: October 27, 2015 — 12:10 pm