2.2.1 Primary Control

Depending on the type of generation, the real power delivered by a generator is controlled by the mechanical power output of a prime mover such as a steam turbine, gas turbine, hydro turbine, or diesel engine. In the case of a steam or hydro turbine, mechanical power is controlled by the opening or closing of valves regulating the input of steam or water flow into the turbine. Steam (or water) input to generators must be continuously regulated to match real power demand. Without this regulation, the machine speed will vary with consequent change in frequency. For satisfactory operation of a power system, the frequency should remain nearly constant.⁶

A schematic block diagram of a synchronous generator equipped with a primary frequency control loop is shown in Figure 2.8. The speed governor senses the change in speed (frequency) via the primary control loop. In fact, primary control performs a local automatic control that delivers reserve power in opposition to any frequency change. The necessary mechanical forces to position the main valve against the high steam (or hydro) pressure is provided by the hydraulic amplifier, and the speed changer provides a steady-state power output setting for the turbine.¹

The speed governor on each generating unit provides the primary speed control function, and all generating units contribute to the overall change in generation, irrespective of the location of the load change, using their speed governing. However, as mentioned, the primary control action is not usually sufficient to restore the system frequency, especially in an interconnected power system, and the supplementary control loop is required to adjust the load reference set point through the speed changer motor.

2.2.2 Supplementary Control

In addition to primary frequency control, a large synchronous generator may be equipped with a supplementary frequency control loop. A schematic block diagram of a synchronous generator equipped with primary and supplementary frequency control loops is shown in Figure 2.9.

The supplementary loop gives feedback via the frequency deviation and adds it to the primary control loop through a dynamic controller. The resulting signal (ΔP_C) is used to regulate the system frequency. In real-world power systems, the dynamic controller is usually a simple integral or proportional-integral (PI) controller. Following a change in load, the feedback mechanism provides an appropriate signal for the turbine to make generation (ΔP_m) track the load and restore the system frequency.

Supplementary frequency control, which is known as load-frequency control (LFC), is a major function of AGC systems as they operate online to control system frequency and power generation. As mentioned, the AGC performance is highly dependent on how the participant generating units would respond to the control action signals. The North American Electric Reliability Council (NERC) separated generator actions into two groups. The first group is associated with large frequency deviations where generators respond through governor action and then in response to AGC signals, and the second group is associated with a continuous regulation process in response to AGC signals only. During a sudden increase in area load, the area frequency experiences a transient drop. At the transient state, there are flows of power from other areas to supply the excess load in this area. Usually, certain generating units within each area are on regulation to meet this load change. At steady state, the generation is closely matched with the load, causing tie-line power and frequency deviations to drop to zero.⁷

Several frequency control criteria and standards are available to find how well each control area must balance its aggregate generation and load. For instance, control performance standards 1 and 2 (CPS1 and CPS2) were introduced by NERC to achieve the optimum AGC performance.^8,9 CPS1 and CPS2 are measurable and can be fixed as normal functions of EMS unit in each control area. Measurements are taken continuously, with data recorded at each minute of operation. CPS1 indicates the relationship between the area control error (ACE) and the system frequency on a 1 min basis; it is the measure of short-term error between load and generation. CPS1’s performance will be good if a control area closely matches generation with the load, or if the mismatch causes system frequency to be driven closer to the nominal frequency. CPS1’s performance will be degraded if the system frequency is driven away from the nominal frequency.

CPS2 will place boundaries on CPS1 to limit net unscheduled power flows that are unacceptably large. Actually, it sets limits on the maximum average ACE for every 10 min period. CPS2 will prevent excessive generation/load mismatches even if a mismatch is in the proper direction. Large mismatches can cause excessive power flows and potential transmission overloads between areas with overgeneration and those with insufficient generation.⁷

2.2.3 Emergency Control

Emergency control, such as load shedding, shall be established in emergency conditions to minimize the risk of further uncontrolled separation, loss of generation, or system shutdown. Load shedding is an emergency control action to ensure system stability, by curtailing system load. The load shedding will only be used if the frequency (or voltage) falls below a specified frequency (voltage) threshold. Typically, the load shedding protects against excessive frequency (or voltage) decline by attempting to balance real (reactive) power supply and demand in the system.

The load shedding curtails the amount of load in the power system until the available generation can supply the remaining loads. If the power system is unable to supply its active (reactive) load demands, the under-frequency (under-voltage) condition will be intense. The number of load shedding steps, the amount of load that should be shed in each step, the delay between the stages, and the location of shed load are the important objects that should be determined in a load shedding algorithm. A load shedding scheme is usually composed of several stages. Each stage is characterized by frequency/ voltage threshold, amount of load, and delay before tripping. The objective of an effective load shedding scheme is to curtail a minimum amount of load, and provide a quick, smooth, and safe transition of the system from an emergency situation to a normal equilibrium state.¹

The interested load shedding type in power system frequency control is UFLS. Most common UFLS schemes, which involve shedding, predetermine the amounts of load if the frequency drops below specified frequency thresholds. There are various types of UFLS schemes discussed in the literature and applied by the electric utilities around the world. A classification divides the existing schemes into static and dynamic (or fixed and adaptive) load shedding types. Static load shedding curtails the constant block of load at each stage, while dynamic load shedding curtails a dynamic amount of load by taking into account the magnitude of disturbance and dynamic characteristics of the system at each stage. Although the dynamic load shedding schemes are more flexible and have several advantages, most real-world load shedding plans are of the static type.¹

There are two basic paradigms for load shedding: a shared LS paradigm and a targeted LS paradigm. The first paradigm appears in the well-known UFLS schemes, and the second paradigm includes some recently proposed wide area LS approaches.¹⁰ Sharing load shedding responsibilities (such as induced by UFLS) are not necessarily an undesirable feature and can be justified on a number of grounds. For example, shared load shedding schemes tend to improve the security of the interconnected regions by allowing generation reserve to be shared. Further, load shedding approaches can be indirectly used to preferentially shed the least important load in the system. However, sharing load shedding can have a significant impact on interregion power flows and, in certain situations, might increase the risk of cascade failure. Although both shared and targeted load shedding schemes may be able to stabilize the overall system frequency, the shared load shedding response leads to a situation requiring more power transmission requirements. In some situations, this increased power flow might cause line overloading and increase the risk of cascade failure.¹

Some useful guideline for UFLS strategies can be found in IEEE.¹¹ The UFLS schemes typically curtail a predetermined amount of load at specific frequency thresholds. The frequency thresholds are also biased, using a disturbance magnitude to shed load at higher-frequency levels in dangerous contingencies.^10,12,13 The UCTE recommends that its members initiate the first stage of automatic UFLS in response to a frequency threshold not lower than 49 Hz.⁵ Based on this recommendation, in case of a frequency drop of 49 Hz, the automatic UFLS begins with a minimum of 10 to 20% of the load. In case of lower frequency, the synchronously interconnected network may be divided into partial networks (islanding). The UFLS is performed at trigger frequencies to curtail the amount of the load (usually about 5 to 20%).

The emergency control schemes and protection plans are usually represented using incremented/decremented step behavior.¹ For instance, according to Figure 2.7, for a fixed UFLS scheme, the function of u_UFLS in the time domain could be considered a sum of the incremental step functions of ΔP_ju(t – t_j), as shown in Figure 2.10a. Here, ΔP_j and t_j denote the incremental amount of load shed and the time instant of the jth load shedding step, respectively. Therefore, for L load shedding steps,

Similarly, to formulate the other emergency control schemes, such as connection and tripping of power plants, u_CT (Figure 2.7), appropriate step functions can be used. Therefore, using the Laplace transformation, one can represent the emergency control effect u_EC in the following abstracted form:

where ΔP_l is the size of the equivalent step load/power changes due to a generation/load event or a load shedding scheme at t_l.

As an example, to show the role of load shedding in stabilizing the power system, the dynamic behavior (voltage-frequency trajectory) of a standard nine-bus IEEE test system, following a serious disturbance (tripping of the largest generator), and applying an intelligent load shedding scheme,¹³ is shown in Figure 2.10b. The load shedding steps are determined by several ellipses, and when the phase trajectory reaches each ellipse, the corresponding load shedding step is triggered. The trajectory is represented in the following complex plane:

where

Here f₀ and v₀ are the frequency and voltage before contingency. The system frequency (and voltage) is reestablished following the five steps of load shedding.

2.3.1 Droop Characteristic

The ratio of speed (frequency) change (Δf) to change in output-generated power (ΔP_g) is known as droop or speed regulation, and can be expressed as

For example, a 5% droop means that a 5% deviation in nominal frequency (from 60 to 57 Hz) causes a 100% change in output power. In Figure 2.11, the droop characteristics for the generating units (R_ki) are properly shown in the primary frequency control loops.

The interconnected generating units with different droop characteristics can jointly track the load change to restore the nominal system frequency. This is illustrated in Figure 2.12, representing two units with different droop characteristics connected to a common load. Two generating units are operating at a unique nominal frequency with different output powers. The change in the network load causes the units to decrease their speed, and the governors increase the outputs until they reach a new common operating frequency. As expressed in Equation 2.6, the amount of produced power by each generating unit to compensate the network load change depends on the unit’s droop characteristic.^14,15

Hence,

2.3.2 Generation-Load Model

For the purposes of AGC synthesis and analysis in the presence of load disturbances, a simple, low-order linearized model is commonly used. The overall generation-load dynamic relationship between the incremental mismatch power (ΔP_m – ΔP_L) and the frequency deviation (Δf) can be expressed as^1,16

where ΔP_m is the mechanical power change, ΔP_L is the load change, H is the inertia constant, and D is the load damping coefficient.

Using the Laplace transform, Equation 2.8 can be written as

Equation 2.9 is represented in the right-hand side of the frequency response model described in Figure 2.11.

2.3.3 Area Interface

In a multiarea power system, the trend of frequency measured in each control area is an indicator of the trend of the mismatch power in the interconnection and not in the control area alone. Therefore, the power interchange should be properly considered in the LFC model. It is easy to show that in an interconnected power system with N control areas, the tie-line power change between area i and other areas can be represented as¹

where ΔP_tie,i indicates the tie-line power change of area i, and T₁₂ is the synchronizing torque coefficient between areas i and j. Equation 2.10 is also realized in the bottom-right side of the AGC block diagram in Figure 2.11. The effect of changing the tie-line power for an area is equivalent to changing the load of that area. That is why in Figure 2.11, the ΔP_tie,i has been added to the mechanical power change (ΔP_m) and area load change (ΔP_L) using an appropriate sign.

In addition to the regulating area frequency, the LFC loop should control the net interchange power with neighboring areas at scheduled values. This is generally accomplished by feeding a linear combination of tie-line flow and frequency deviations, known as area control error (ACE), via supplementary feedback to the dynamic controller. The ACE can be calculated as follows:

where β_i is a bias factor, and its suitable value can be computed as¹⁶

The block diagram shown in Figure 2.11 illustrates how Equation 2.11 is implemented in the supplementary frequency control loop. The effects of local load changes and interface with other areas are also considered as the following two input signals:

Each control area monitors its own tie-line power flow and frequency at the area control center, and the combined signal (ACE) is allocated to the dynamic controller. Finally, the resulting control action signal is applied to the turbine-governor units, according their participation factors. In Figure 2.11, M_ki(s) and α_ki are the governor-turbine model and AGC participation factor for generator unit k, respectively.

2.3.4 Spinning Reserve

There are different definitions for the spinning reserve term. Using UCTE terminology, it is a tertiary reserve that can be available within 15 min and is provided chiefly by storage stations, pumped-storage stations, gas turbines, and thermal power stations operating at less than full output. While based on the definition provided by NERC, it is an unloaded generation that is synchronized and ready to serve additional demand.¹⁷

The spinning reserve can be simply defined as the difference between capacity and existing generation level. It refers to spare power capacity to provide the necessary regulation power for the sum of primary and secondary control issues. Regulation power is required power to bring the system frequency back to its nominal value. The frequency-dependent reserves are automatically activated by the AGC system, when the frequency is at a lower level than the nominal value (50 or 60 Hz, depending on the system).

Always, the market operator needs to ensure that there is enough reserved capacity for potential future occurrences. The size of the AGC reserve that is required depends on the size of load variation, schedule changes, and generating units. In a deregulated environment, the reserve levels may be influenced by the market operation. If too much energy is traded, the market operator must contract more reserves to ensure that the predicted demand can be met.¹⁸ Additional reserves need to be activated to restore the used power spinning reserves in preparation for further incidents.

2.3.5 Participation Factor

The participation factor indicates the amount of participation of a generator unit in the AGC system. Following a load disturbance within the control area, the produced appropriate supplementary control signal is distributed among generator units in proportion to their participation, to make generation follow the load. In a given control area, the sum of participation factors is equal to 1:

In a competitive environment, AGC participation factors are actually time-dependent variables and must be computed dynamically by an independent organization based on bid prices, availability, congestion problems, costs, and other related issues.¹

2.3.6 Generation Rate Constraint

Although considering all dynamics to achieve an accurate perception of the AGC subject may be difficult and not useful, considering the main inherent requirement and the basic constraints imposed by the physical system dynamics to model/evaluate the AGC performance is important. An important physical constraint is the rate of change of power generation due to the limitation of thermal and mechanical movements, which is known as generation rate constraint (GRC).¹

Rapidly varying components of system signals are almost unobservable due to various filters involved in the process, and an appropriate AGC scheme must be able to maintain sufficient levels of reserved control range and control rate. Therefore, the rate of change in the power output of generating units used for AGC must in total be sufficient for the AGC purpose. It is defined as a percentage of the rated output of the control generator per unit of time. The generation rates for generation units, depending on their technology and types, are different. Typical ramp rates for different kinds of units (as a percentage of capacity) for diesel engines, industrial GT, GT combined cycle, steam turbine plants, and nuclear plants are 40%/min, 20%/min, 5 to 10%/min, 1 to 5%/min, and 1 to 5%/min, respectively.¹⁹ In hard-coal-fired and lignite-fired power plants, this rate is 2 to 4%/min and 1 to 2%/min, respectively.⁵

2.3.7 Speed Governor Dead-Band

If the input signal of a speed governor is changed, it may not immediately react until the input reaches a specified value. This phenomenon is known as speed governor dead-band. All governors have a dead-band in response, which is important for AGC systems. Governor dead-band is defined as the total magnitude of a sustained speed change, within which there is no resulting change in valve position.

The maximum value of dead-band for governors of large steam turbines is specified as 0.06% (0.036 Hz).²⁰ For a wide dead-band the AGC performance may be significantly degraded. An effect of the governor dead-band on the AGC operation is to increase the apparent steady-state frequency regulation. In Figure 2.11, the GRC and speed governor dead-band are considered by adding limiters and hysteresis patterns to the governor-turbine system models.

2.3.8 Time Delays

In new power systems, communication delays are becoming a more significant challenge in system operation and control. Although, under a traditional AGC structure, the problems associated with the communication links may ignorable, considering the problems that may arise in the communication system in use of an open communication infrastructure to support the ancillary services in a restructured environment is important. It has been shown that time delays can degrade the AGC performance seriously.²¹ The AGC performance declines when the time delay increases.

The time delays in the AGC systems mainly exist on the communication channels between the control center and operating stations—specifically on the measured frequency and power tie-line flow from RTUs or IEDs to the control center, and the delay on the produced rise/lower signal from the control center to individual generation units.²² Furthermore, all other probable data communication, signal processing, and filtering among an AGC system introduce delays that should be considered. These delays are schematically shown in Figure 2.11.