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 decommitment 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 setpoint 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 overall 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.
AP D —— * f0 +——— 2H 0 2H 
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:
Where:
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 subsections 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.)
Where:
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:
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

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,
Af=21/350=0.06HZ
Frequency=600.06=59.94HZ
• 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 deadband region are all key aspects in assessing the need and extent of primary frequency response associated with a generator.