5
Power System Control: Fundamentals and New Perspectives
The term power systems control is used to define the application of control theorems and relevant technologies to enhance the power system functions during normal and abnormal operations. Power system control refers to keeping a desired performance and stabilizing power system following various disturbances, such as short circuits and loss of generation and/or load. Power system stability and control was first recognized as an important problem in the 1920s [1,2]. Over the years, numerous modeling/simulation programs, synthesis/analysis methodologies, and protection schemes have been developed. Power system control can take different forms, which are influenced by the type of instability phenomena. A survey on the basics of power system controls, literature, and achievements is given in Refs [3,4].
In this chapter, fundamental concepts and definitions of power system stability and control are emphasized. The role of power system control in preserving system integrity and restoring the normal operation subjected to physical disturbances is described and some challenges, opportunities, and new perspectives concerning the integration of renewable energy options and distributed generators are introduced.
5.1 Power System Stability and Control [5]
Power system stability is defined as “the ability of an electric power system, for a given initial operating condition, to regain a state of operating equilibrium after being subjected to a physical disturbance, with most system variables bounded so that practically the entire system remains intact” [6]. Power system stability phenomena are known as rotor angle stability, voltage stability, and frequency stability.
Rotor angle stability is the ability of the power system to maintain synchronization after being subjected to a disturbance. In case of transient (large disturbance) angle stability, a severe disturbance does allow a generator to deliver its output electricity power into the network. Small-signal (steady-state) angle stability is the ability of the power system to maintain synchronization under small disturbances. The rotor angle stability has been fairly guaranteed by power system stabilizers (PSS), thyristor exciters, fast fault clearing, and other stability controllers and protection actions such as generator tripping.
Voltage stability is the ability of a power system to maintain steady acceptance voltages at all system buses after being subjected to a disturbance from an assumed initial equilibrium point. A system enters a state of voltage instability when a disturbance changes the system condition to make a progressive fall or rise of voltages of some buses. Loss of load in an area, tripping of transmission lines, and other protected equipment are possible results of voltage instability.
Frequency stability is the ability of a power system to maintain system frequency within the specified operating limits. Generally, frequency instability is a result of a significant imbalance between load and generation, and it is associated with poor coordination of control and protection equipment, insufficient generation reserves, and inadequacies in equipment responses.
The size of disturbance, physical nature of instability, the dynamic structure, and the time span are important factors to determine the instability form. The above instability classification is mainly based on dominant initiating phenomena. Each instability form does not always occur in its pure form. One may lead to the other, and the distinction may not be clear. However, distinguishing between different instability forms is important in understanding the underlying causes of the problem in order to develop appropriate design and operating procedures.
To maintain system stability and desirable performance, numerous control loops are in use in a power system. Power system controllers are of many types with different control tasks, including generation excitation controls, prime mover controls, generator/load tripping, fast fault clearing, high speed reclosing, reactive power compensation, load-frequency control, current injection, fast phase angle control, and high-voltage DC (HVDC) special controls.
Power system controls attempt to return the system from an off-normal operating state to a normal operating state. Classifying the power system operating states to normal, alert, emergency, in extremis, and restorative is conceptually useful for designing appropriate control systems. In the normal state, all system variables (e.g., voltage and frequency) are within the normal range. In the alert state, all system variables are still within the acceptable range. However, the system may be ready to move into the emergency state following a disturbance. In the emergency state, some system variables are outside of the acceptable range and the system is ready to fall into the in extremis state. Partial or system wide blackout could occur in the in extremis state. Finally, energizing the system or its parts and reconnecting/resynchronizing of system parts occurs during the restorative state.
From the operating state point of view, power system controls can be mainly divided into two different categories: normal/preventive controls, which are applied in the normal and alert states to stay in or return into normal condition, and emergency controls, which are applied in emergency or in in extremis state to stop the further progress of the failure and return the system to a normal or alert state.
Automatic frequency and voltage controls are part of the normal and preventive controls, while some control schemes like underfrequency load shedding (UFLS), undervoltage load shedding (UVLS), and special system protection plans can be considered as emergency controls. Control command signals for normal/preventive controls usually include active power generation set points, flow controlling reference points (FACTS), voltage set point of generators, static VAR compensator (SVC), reactor/capacitor switching, and so on. Emergency control measures are some control commands such as tripping of generators, shedding of load blocks, opening of interconnection to neighboring systems, and blocking of transformers tap changer.
Most control loops such as prime mover and excitation controls operate directly on the generation site, and are located at the power plants. In a power plant, the governor voltage and reactive power output are regulated by excitation control, while energy supply system parameters (temperatures, flows, and pressures) and speed regulation are performed by prime mover controls. Automatic generation control balances the total generation and load (plus losses) to reach the nominal system frequency and scheduled power interchange with neighboring systems.
Furthermore, there are many controls and protection systems on the demand side in transmission and distribution networks such as switching capacitor/reactors, tap-changing/phase shifting transformers, HVDC controls, synchronous condensers, and static VAR compensators. Despite numerous existing nested control loops that control different quantities in the system, working in a secure attraction region with a desired performance is the objective of an overall power system control strategy.
For the purpose of dynamic analysis and control synthesis, it is noteworthy to know the timescale of various control loops. The timescale of interest for rotor angle stability in transient (large disturbance) stability studies is usually limited to 3–10 s, and in steady-state (small-signal) studies is on the order of 10–20 s. The rotor angle stability is known as a short-term stability problem, while the voltage stability problem can be either a short-term or a long-term stability problem. The time frame of interest for voltage stability problems may vary from a few seconds to several minutes. Although power system frequency stability is impacted by fast as well as slow dynamics, the time frame will range from a few seconds to several minutes [7]. Therefore, the frequency stability is known as a long-term stability problem.
For the purpose of power system control designs, generally the control loops at lower system levels (locally in a generator) are characterized by smaller time constants than the installed control loops at a higher system level. For example, the automatic voltage regulator (AVR), which regulates the voltage of the generator terminals to the reference value, responds typically in a timescale of a second or less. The secondary voltage control, which determines the reference values of the voltage controlling devices, among which are the generators, operates in a timescale of several seconds or minutes. That means these two control loops are virtually decoupled. A schematic diagram showing different control timescales is presented in Fig. 5.1.
Figure 5.1 Schematic diagram of control timescales.
5.2 Angle and Voltage Control
As mentioned, angles of nodal voltages (rotor/power angles), nodal voltage magnitudes, and network frequency are three important quantities for power system operation and control. They are also significant in the stability classification point of view. This section is focused on angle and voltage stability, which can be divided into small- and large-disturbance stability. Angle and voltage stability refer to damping of power swings inside subsystems and between subsystems on an interconnected grid and voltage excursion during variation beyond specified threshold levels, respectively.
The risk of losing angle and voltage stability can be significantly reduced by using proper control devices inserted into the power system to find a smooth shape for the system dynamic response. Important control devices for stability enhancement are known as PSS, AVR, and FACTS devices.
The generators are usually operated at constant voltage by using an AVR, which controls the excitation of the machine via the electric field exciter. The exciter supplies the field winding of the synchronous machine with direct current to generate the required flux in the rotor.
A PSS is a controller, besides being the turbine-governing system, performs an additional supplementary control loop to the AVR system of a generating unit. A common structure for the PSS–AVR is shown in Fig. 5.2. There are a number of possible ways for constructing the PSS–AVR system, in which a particular case is already introduced in Fig. 4.5. The necessity of the supplementary control loop is due to the conflict behavior of rotor speed and voltage dynamics.
Figure 5.2 PSS and AVR control loops.
In the steady state, ΔvPSS must be equal to zero so that it does not distort the voltage regulation process. However, in the transient state, the generator speed is not constant, the rotor swings, and ΔV undergoes variations caused by the change in rotor angle [8,9]. This voltage variation is compensated by the PSS providing a damping signal ΔvPSS that is in phase with generator speed change (Δω).
As shown in the general structure of the PSS (Fig. 5.2), the input signal is passed through a combination of low- and high-pass filters. To provide the required amount of phase shift, the prepared signal is then passed through a lead-lag compensator. Finally, the PSS signal is amplified and limited to provide an effective output signal (ΔvPSS). Typically, the rotor speed/frequency deviation (Δω/Δf), the generator active power deviation (ΔPe), or a combination of rotor speed/frequency and active power changes can be considered as input signal to the PSS.
In many power systems, advanced measurement devices and modern communications are already being installed. Using these facilities, as mentioned in Section 4.1, the parameters of the PSS and AVR can be adjusted using an online monitoring-based tuning mechanism. This control architecture is simply shown in Fig. 5.3.
Figure 5.3 A structure for advanced PSS–AVR tuning approaches.
Like frequency control, voltage control is also characterized via several control loops on different system levels. The AVR loop, which regulates the voltage of generator terminals, is located on lower system levels and responds typically in a timescale of a second or less. On the other hand, the secondary voltage control, which determines the voltage reference values of the distributed voltage compensators (e.g., AVR), is activated on a higher system level and operates in a timescale of tens of seconds or minutes. Secondary voltage control is required to coordinate adjustment of the set points of the AVRs and other reactive power sources in a given network to enhance voltage stability of the grid.
The voltage stability can be further enhanced with the use of a higher control level (with a timescale of several minutes) known as tertiary voltage control, based on the overall grid economic optimization. A typical generic of the mentioned three voltage control levels is discussed in Ref. [7].
5.3 Frequency Control [10,11]
A severe system stress resulting in an imbalance between generation and load seriously degrades the power system performance (and even stability), which cannot be described in conventional transient stability and voltage stability studies. This type of usually slow phenomena must be considered in relation with the power system frequency control issue.
Frequency deviation is a direct result of an imbalance between the electrical load and the power supplied by the connected generators, so it provides a useful index to indicate the generation and load imbalance. A permanent off-normal frequency deviation may affect power system operation, security, reliability, and efficiency by damaging equipment, degrading load performance, overloading transmission lines, and triggering the protection devices.
Since the frequency generated in an electric network is proportional to the rotation speed of the generator, the problem of frequency control may be directly translated into a speed control problem of the turbine-generator unit. This is initially overcome by adding a governing mechanism that senses the machine speed and adjusts the input valve to change the mechanical power output to track the load change and to restore frequency to the nominal value. Depending on the frequency deviation range, different frequency control loops may be required to maintain power system frequency stability.
The typical frequency control loops are simply represented in Fig. 5.4. Under normal operation, small frequency deviations can be attenuated by the primary control. For larger frequency deviation (off-normal operation), according to the available amount of power reserve, the secondary control, which is known as load-frequency control (LFC) is responsible for restoring system frequency. The LFC is the main component of automatic generation control (AGC). However, for a serious load–generation imbalance associated with rapid frequency changes following a significant fault, the LFC system may be unable to restore frequency. In this situation, another action must be applied using tertiary control, standby supplies, or emergency control and protection schemes (e.g., UFLS) as the last option to decrease the risk of cascade faults, additional generation events, and load/network and separation events. The tertiary and emergency controls could be realized by the energy management system (EMS), independent system operator (ISO), or market operator.
Figure 5.4 Frequency control loops.
In a power system, all four forms of frequency control are usually present. The demand side can also participate in frequency control through the action of frequency-sensitive relays, which disconnect some loads at given frequency thresholds (in the UFLS) or using self-regulating effect of frequency-sensitive loads, such as induction motors. Figure 5.5 shows the discussed frequency control loops and corresponding power reserves. The amount of required power reserve depends on several factors including the type and size of load–generation imbalance.
Figure 5.5 Frequency control levels and power reserves.
Primary frequency control loop provides a local and automatic frequency control by adjusting the speed governors in the time frame of seconds after a disturbance. The secondary frequency control loop initializes a centralized and automatic control task using the assigned spinning reserve, which is activated in the time frame of a few seconds to minutes after a disturbance. The tertiary frequency control is usually known as a manual frequency control by changing the dispatching of generating units, in the timescale of tens of minutes up to hours after a disturbance.
In the conventional power grids, the primary control reserves a maximum duration of 30 s, whereas in the modern power grids and microgrids with lower inertia, the time constants are much smaller. Virtual inertia can be considered as an effective solution to support the primary frequency control and compensate for the fast frequency changes.
The typical frequency control loops are represented in Fig. 5.4, in a simplified scheme. In a large multiarea power system, all four forms of frequency control (primary, secondary, tertiary, and emergency) are usually present. The demand side also participates in the frequency control through the action of frequency-sensitive relays, which disconnect some loads at the given frequency thresholds (in the UFLS). The demand side may also contribute to frequency control using the self-regulating effect of frequency-sensitive loads, such as induction motors. However, this type of contribution is not always taken into account in the calculation of the overall frequency control response.
5.3.1 Frequency Control Dynamic
In addition to the primary frequency control, a large synchronous generator may be equipped with the secondary frequency control loop. A frequency response model for control area i in a multiarea power system is shown in Fig. 5.6. In this figure, 
, 
, 
, and 
are the area's constant inertia, damping coefficient, bias factor, and frequency deviation, respectively. 
indicates the tie-line power change of area i, and is the synchronizing torque coefficient between area i and area j. Here, 
, 
, and 
are the governor-turbine model, droop characteristic, and participation factor for generator unit k in area i, respectively.
Figure 5.6 Frequency response model.
The synchronous generators are equipped with primary and secondary frequency control loops. The secondary loop performs a feedback via the frequency deviation and adds it to the primary control loop through a dynamic controller. The resulting signal (
) is used to regulate the system frequency. In real-world power systems, usually the dynamic controller is a simple integral (I) or proportional-integral (PI) controller. Following a change in the load, the feedback mechanism provides an appropriate signal for the turbine to make generation (
) track the load and restore the system frequency.
In addition to the area frequency regulation, the secondary control 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 secondary feedback to the dynamic controller. The ACE can be calculated as follows:
where bias factor 
can be computed as
The block diagram shown in Fig. 5.6 illustrates how Equation (5.1) is implemented in the secondary frequency control loop. The effects of local load changes and interface with other areas are also considered as the following two input signals:
where ΔPLi and Tij are the load disturbance (in area i) and synchronizing coefficient of two areas (i and j), respectively.
As mentioned, the secondary loop performance is highly dependent on how the participant generating units would respond to the control action signals. The North American Electric Reliability Council separated generator actions into two groups. The first group is associated with large frequency deviations where generators would respond through governor action and the second group is associated with a continuous regulation process in response to the secondary frequency control signals only. During a sudden increase in area load, the area frequency experiences a transient drop. At the transient state, there would be flows of power from other areas to supply the excess load in that area. Usually, certain generating units within each area would be on regulation to meet this load change. At steady state, the generation would be closely matched with the load, causing tie-line power and frequency deviations to drop to zero.
In an interconnected power system the control area concept needs to be used for the sake of synthesis and analysis of the secondary frequency control system. A control area is an electric network that is managed under a common automatic control scheme maintaining frequency and tie-line interchanges close to the specified nominal values by balancing load and generation. The frequency is assumed to be the same in all points of a control area.
In practice, to clear the fast changes and probable added noises, system frequency gradient and ACE signals must be filtered before being used in the secondary frequency control loop. If the ACE signal exceeds a threshold at interval 
, it will be applied to the controller block. The controller can be activated to send higher/lower pulses to the participant generation units if its input ACE signal exceeds a standard limit. Delays, ramping rate, and range limits are different for various generation units. Concerning the limit on generation, governor dead band and time delays, the LFC model becomes highly nonlinear; hence, it will be difficult to use the conventional linear techniques for performance optimization and control design [5].
For the purpose of frequency control 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 (
) and the frequency deviation (
) can be expressed as
where 
is the mechanical power change, 
is the load change, 
is the inertia constant, and 
is the load damping coefficient. Using the Laplace transform, Equation (5.4) can be written as
Equation (5.5) is represented on the right-hand side of the frequency response model in Fig. 5.6.
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 frequency response 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 as [5]
Equation (5.6) is realized on the right-hand side of the frequency response block diagram in Fig. 5.6. The effect of changing the tie-line power for an area is equivalent to changing the load of that area. That is why, 
has been added to the mechanical power change (
) and area load change (
) using an appropriate sign in Fig. 5.6.
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.
The participation factor indicates the amount of participation of a generator unit in the secondary frequency control system. Following a load disturbance within the control area, the produced appropriate 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, the participation factors are actually time-dependent variables and must be computed dynamically based on bid prices, availability, congestion problems, costs, and other related issues [5,10].
As mentioned, in the case of a large generation loss disturbance, the scheduled power reserve may not be enough to restore the system frequency, and the power system operators may follow an emergency control plan such as UFLS. The UFLS strategy is designed so as to rapidly balance the demand of electricity with the supply and to avoid a rapidly cascading power system failure. Allowing normal frequency variations within expanded limits will require the coordination of primary control and scheduled reserves with generator load set points; for example, underfrequency generation trip (UFGT), overfrequency generation trip (OFGT), or overfrequency generator shedding (OFGS) and other frequency-controlled protection devices.
In the case of contingency analysis, the emergency protection and control dynamics must be adequately modeled in the frequency response model. Since they influence the power generation–load balance, the mentioned emergency control dynamics can be directly included to the system frequency response model. This is made by adding an emergency protection/control loop to the primary and secondary frequency control loops, as shown in Fig. 5.6. The 
, 
, and 
represent the dynamics effects of the UFLS, UFGT, and OFGT actions, respectively.
The emergency control schemes and protection devices dynamics are usually represented using incremented/decremented step behavior. Thus, in Fig. 5.6, for simplicity, the related blocks can be represented as a sum of incremental (decremental) step functions. For instance, for a fixed UFLS scheme, the function of 
in the time domain could be considered as a sum of the incremental step functions of 
. Therefore, for L load shedding steps
where 
and 
denote the incremental amount of load shed and time instant of the jth load shedding step, respectively. Similarly, to formulate the 
, 
, and other emergency control schemes, appropriate step functions can be used. Therefore, using the Laplace transformation, it is possible to represent 
in the following summarized form:
where 
is the size of equivalent step load/power changes due to a generation–load event or a load shedding scheme at 
.
The effect of tertiary control loop in a control unit (e.g., supervisory control and data acquisition/dispatching center) organized by the market operator in relation with Gencos and security plans is also shown in Fig. 5.6.
5.3.2 Operating States and Power Reserves
Frequency provides a useful index to indicate the system generation and load imbalance. Any short-term energy imbalance results in an instantaneous change in system frequency as the disturbance is initially offset by the kinetic energy of a rotating plant. As mentioned, off-normal frequency deviations can impact the power system operation, system reliability, and efficiency. Large frequency deviations can damage equipment, degrade load performance, overload transmission lines, and trigger the protection relays and may ultimately lead to a system collapse.
Depending on the size of the frequency deviation experienced, primary, secondary, tertiary, and emergency controls may all be required to maintain power system frequency. One method of characterizing frequency deviations experienced by a power system is in terms of frequency deviation ranges and related control actions as shown in Table 5.1.
Table 5.1 Frequency Deviation Ranges and Associated Control Actions
| Δf | Condition | Control Action | Reserve |
 |
No contingency or load event | Normal operating | Continuous/spinning |
 |
Generation–load or network event | AGC operating | Continuous/spinning |
 |
Contingency/separation event | Tertiary/emergency operating |
Contingency/spinning, Nonspinning |
 |
Multiple contingency event | Emergency operating | Nonspinning/load shedding |
The frequency variation ranges 
, 
, 
, and 
are identified in terms of different power system operating conditions, specified in terms of local regulations. Under normal operation, frequency is maintained near the nominal frequency by balancing generation and load. That is, the small frequency deviations up to 
can be attenuated by the governor natural autonomous response (primary control). The secondary control can be used to restore area frequency deviation of more than 
. In particular, a secondary control system must be designed to maintain the system frequency and tie-line power deviations within the limits of specified operating standards, using the available spinning reserves. The value of 
is mainly determined by the available amount of operating reserved power in the system.
For large imbalances in real power associated with large/rapid frequency changes (e.g., 
and 
frequency deviation events) following a severe disturbance/fault, the secondary control loop may be unable to recover the system frequency. In this case, to prevent additional generation events, load/network events, separation events or multiple contingency events, the tertiary and/or emergency controls, as well as other protection schemes must be used to restore the system frequency.
According to the UCTE commitment [12], a sudden loss of 3000 MW of generating capacity must be offset by primary control alone, without the need for load shedding. Likewise, the sudden load shedding of 3000 MW in total must not lead to a frequency deviation exceeding 
(180 mHz).
In order to have a reliable and secure operation, enough regulation power reserve should be available, so that the ACE, the instantaneous difference between the actual and the reference values for the power interchange of a control area, is kept within reasonable bounds. Power reserves ensure that capacity is available when needed to maintain secure power system operations following an imbalance in the load–generation system.
In a power system market, the reserves must be carefully planned and purchased so that the system operator is able to use them when required. The system operator guarantees effective use of assets, including the dispatch of energy and the dispatch of spinning (regulation) and nonspinning (contingency) reserves, and organizes the energy and ancillary services markets. The market operator must activate these power reserves to meet the standard performance indices in a timely and economical manner.
The reserves required during normal conditions are known as spinning reserve or regulation reserve, and are used for continuous regulation and energy imbalance management. This reserve is used to track minute-to-minute fluctuations in the system load–generation pattern, and is provided by online resources with automatic controls that respond rapidly to the raise/down control command signal.
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. The time response of spinning reserve for primary frequency regulation is about 30 s, which is much faster than the spinning reserve time response for secondary frequency control (within 15 min). Regulation power is the 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 in a lower level than the nominal value (50 or 60 Hz depending on the system).
Another type of spinning reserve is known as the energy imbalance management reserve that serves as a bridge between the regulation service and the hourly or half-hourly bid-in energy schedules, similar to but slower than continuous regulation. It is used for load-following problems in the tertiary level of frequency control issue. It also serves a financial/settlement function in clearing spot markets [12]. The energy imbalance management reserve must be available within 30 min at a specified minimum rate, typically 2 MW/min.
The nonspinning reserves are instantaneous contingency or replacement reserves that are used during system contingencies. A contingency is a trip of a transmission line or generator, a loss of load, or some combination of these events. This contingency in turn causes other problems, such as a transmission line overload, and significant frequency/voltage deviations or frequency/voltage instability. Contingency reserves are a special percentage of generation capacity resources held back or reserved to meet emergency needs. The contingency reserve services are often referred to as operating reserves. Concerning the frequency control issue, the nonspinning reserves can be classified into two categories [12]: instantaneous contingency reserves and replacement reserves.
Instantaneous contingency reserves (also referred to as the contingency nonspinning reserves) are provided by online generating units (e.g., pumped storage power stations) that are able to rapidly increase output or decrease consumption after receiving a control command in response to a major disturbance or other contingency event. The time response of this reserve, which is known as a quick-start operating reserve, is within 10–15 min.
The replacement reserves will be provided by generating units (e.g., combined-cycle gas-turbine power plants) with a slower response time (up to 30 min) that can be called upon to replace or supplement the instantaneous contingency reserve as standby reserves following receiving a dispatching command or control action signal from the tertiary or emergency control levels. These reserves are typically activated in the case of a generator outage or power imbalances caused by severe events. The instantaneous contingency and replacement reserves are usually activated by the central system operator through a manual control process, while the spinning reserves are usually activated automatically.
Figure 5.5 shows the discussed frequency control levels and corresponding power reserves. In order to determine the sufficient amount of power reserves for proper load–generation balance control with acceptable reliability, it is necessary to refer to the existing reliability standards and assigned performance indices by the relevant technical committees. The amount of required power reserve depends on several factors, including the type and size of imbalance (load–generation variation).
5.4 Supervisory Control and Data Acquisition
Considering the change of the power market from centralized to decentralized decision making as well as separation of the power market from power system reliability, control centers have to be modified to cope with the changing of the power system environment. In a modern power system, the supervisory control and data acquisition (SCADA) has an important role in successful operation and control, particularly in the energy management system (EMS). The SCADA together with security control, AGC, and load management are the major units in the application layer of a modern EMS [13]. The AGC process is performed in a control center remote from generating plants, while power production is controlled by turbine governors at the generation site. The AGC communicates with SCADA, load management unit, and security assessment and control center in the EMS, as shown in Fig. 5.7 [14].
Figure 5.7 Application layer of a modern EMS.
The SCADA block covers a number of applications including analog, status and accumulator data processing, limit checking, data processing, historical data recording, tagging, control actions, and load shedding. The generation control and scheduling block consist of reserves monitoring, AGC performance evaluation, transaction scheduling, market interface, and load forecasting. Finally, the security assessment and control system includes topology processing, state estimation, real-time stability assessment, loss sensitivities, contingency analysis, security enhancement, optimal power flow calculation, off-line stability evaluation, and disturbance/fault analysis.
Security assessment and control system includes methods to evaluate power system stability in different conditions and provide the necessary control actions. The main components of this system according to CIGRE Report No. 325 are shown in Fig. 5.8. Measurements of power system quantities and devices status are collected by SCADA and individual PMU/intelligent electronic devices (IEDs) in the data measurement block. The collected data are used to identify the power system parameters in the online system modeling block. Then, the computation block determines the validation/accuracy of the obtained models as well as the overall security assessment. Finally, the results are used for reporting, monitoring, preventive/corrective controls, as well as other functions such as archiving and modes studying.
Figure 5.8 Structure of security assessment and control system.
A simplified architecture for the SCADA/EMS center and other important connected blocks is shown in Fig. 5.9. System data are collected from remote terminal units (RTUs), IEDs, and integrated substation automation systems (SASs) by using standard communication protocols (e.g., IEC-60870-5-101). The information is exchanged over the Internet and/or via interutility control center communication protocol (ICCP) such as 60870-6-TASE2. The SCADA/EMS also includes a fault/disturbance recording system, a historical information system, and several monitoring and analysis tools that enable the operators to view and organize the system operation.
Figure 5.9 Conceptual overview of SCADA/EMS structure.
The SCADA system consists of a master station to communicate with the RTUs and IEDs for a wide range of monitoring and control processes across a power system. In a modern SCADA system, the monitoring, processing, and control functions are distributed among various servers and computers that communicate in the control center using a real-time local area network (LAN). A simplified SCADA center is shown in Fig. 5.10. Although nowadays many data processing and control functions are moved to the IEDs, the power systems still need a master station or control center to organize/coordinate various applications.
Figure 5.10 A simplified structure for a typical SCADA center.
As shown in Fig. 5.10, the human–machine interface (HMI), application servers, and communication servers are the major elements of the SCADA system. The HMI consists of a multivideo display (Multi-VD) interface and a large display or map-board/mimic-board to display an overview of the power system. The application servers are used for general database, historical database, data processing, real-time control functions, EMS configuration, and system maintenance. The communication servers are used for data acquisition from RTUs/IEDs, and data exchange with other control centers.
The data communication, system monitoring, alarms detection, and control commands transmission are the common actions in a SCADA center. Moreover, the SCADA/EMS system performs load shedding and special control schemes in cooperation with the AGC system and security control unit. Various security methods and physical options can be applied to protect SCADA systems. To improve operation security, usually a dual configuration for the operating computers/devices and networks in the form of primary and standby configuration is used.
In a modern SCADA/EMS station, the performed control and monitoring processes are highly distributed among several servers, monitors, and communication devices. Using a distributed structure has many advantages such as easily upgrading of hardware/software parts, reducing costs, and limiting the effect of failures. The SCADA system uses an open architecture for communication with other systems, and to support interfaces with various vendors' products [15]. A mix of communication technologies such as wireless, fiber optics, and power line communications could be a viable solution in a SCADA system.
As mentioned, modern communications are already being installed in many power systems. Substations at both transmission and distribution levels are being equipped with advanced measurement and protection devices as well as new SCADA systems for supervision and control. Communication between control units is also being modernized as is the communication between several subsystems of the high level control at large power producers at the EMS level. These are often based on open protocols, notably the IEC61850 family for SCADA-level communication with substations and distributed generating units, and the IEC61968/61970 CIM family for EMS-level communication between control centers [16].
In some cases, the role of a SCADA system is distributed between several regional SCADAs; usually, one of them is a coordinator and works as the master SCADA center. A real view of a regional SCADA is shown in Fig. 5.11.
Figure 5.11 A regional SCADA, West Regional Electric Co., Kermanshah.
In real-power system structures, the SCADA/EMS effectively uses IEDs for doing remote monitoring and control actions. The IEDs as monitoring and control interface to the power system equipment can be installed in remote (site/substation) control centers and can be integrated using suitable communication networks. This issue facilitates to accomplish a remote site control system similar to the major station in the SCADA/EMS. A simplified architecture is presented in Fig. 5.12.
Figure 5.12 A simplified architecture including remote site control and SCADA system.
A remote site control center may consist of an RTU, IEDs, HMI database server, and synchronizing time generator. The RTU and IEDs are for communication with the SCADA/EMS station, remote access control functions, data measurement/concentration, and status monitoring. The synchronizing time generator is typically a GPS satellite clock that distributes a time signal to the IEDs.
The local access to the IEDs and the local communication can be accomplished over a LAN, while, the remote site control center is connected to the SCADA/EMS, EMS, and other engineering systems through the power system wide area network. The interested readers can find relevant standards for SCADA/EMS systems, substation automation, remote site controls with detailed architectures, and functions of various servers, networks, and communication devices in Ref. [15].
5.5 Challenges, Opportunities, and New Perspectives
5.5.1 Application of Advanced Control Methods and Technologies
In the last 20 years, intelligent systems applications have received increasing attention in various areas of power systems such as operation, planning, control, and management. Numerous research papers indicate the applicability of intelligent techniques to power systems. While many of these systems are still under investigation, there already exist a number of practical implementations of intelligent systems in many countries across the world. In conventional schemes, power system operation, planning, control, and management are based on human experience and mathematical models to find solutions; however, power systems have many uncertainties in practice. Namely, those mathematical models provide only for specific situations of the power systems under respective assumptions. With these assumptions, the solutions of power system control analysis/synthesis problems are not trivial. Therefore, there exist some limitations for the mathematical model based schemes. In order to overcome these limitations, applications of intelligent technologies such as knowledge-based expert systems, fuzzy systems, artificial neural networks, genetic algorithms, Tabu search, and other intelligent technologies have been investigated in a wide area of power system problems to provide a reliable and high-quality power supply at minimum cost. In addition, recent research works indicate that more emphasis has been put on the combined usage of intelligent technologies for further improvement of the operation, control, and management of power systems.
Several surveys on the worldwide application of intelligent methodologies on power systems have been recently published. Intelligent and advanced systems are currently used in many utilities across the developed countries. Some application areas of intelligent technologies in Japanese power system utilities are presented in Ref. [10]. Many applications have been proposed in literatures in those areas to demonstrate the advantages of intelligent systems over conventional systems. A certain number of actual implementation of intelligent systems is already working toward better and more reliable solutions for control and operation problems in power systems.
As mentioned earlier, there already exists a quite good number of implementations of intelligent systems in Japanese utilities. Some of them are now at their renewal stages. However, because of the reasons listed in Table 5.2, the renewals of some of the intelligent systems will be postponed. Most of these obstacles will be solved by further developments of software/hardware technologies.
Table 5.2 Problems for Future Extension of Intelligent Systems in Real Power Systems
| Amount of additional investment |
| Cost of maintenance |
| Unsatisfactory performance |
| Required processing speed |
| Shortage of actual operation |
| Black box based operation |
| Accuracy of solutions |
| Acceptability by human operator |
| Industry owners are too conservative! |
Currently, power system operation and control in all aspects is undergoing fundamental changes due to restructuring, expanding of functionality, rapidly increasing amount of renewable energy sources, and emerging of new types of power generation and consumption technologies. This issue opens the way to realizing new/powerful intelligent techniques.
5.5.2 Standards Updating
Power system operation is always in a changing state due to the integration of new power sources, maintenance schedules, unexpected outages, and changing interconnection schedules and fluctuations in demand, generation, and power flow over transmission lines. Increasing size, restructuring, emerging of renewable energy sources (RESs), and new uncertainties provides a variable nature for power systems, and it imposes the necessity for continuously updating operating standards. In this direction, frequency and voltage performance standards compliance verification remains a major open issue. Interconnection procedures and standards should be also reviewed to ensure that operating control schemes and their responses are in a consistent manner in all power generation technologies, specifically RESs and variable generation technologies. This is because uncertainty and variability are their two major attributes that distinguish them from conventional forms of generation and may impact the overall system planning and operations.
Therefore, the control issues and related standards may evolve into new guidelines. The standards redesign must be done in both normal and abnormal conditions, and they should allow for the introduction of renewable power generation and modern distributed generator technologies.
5.5.3 Impacts of Renewable Energy Options
There is a rising interest on the impacts of RESs on power system operation and control, as the use of RESs increases worldwide. The RESs certainly affect the dynamic behavior of the power system in a way that might be different from conventional generators. High renewable energy penetration in power systems may increase uncertainties during abnormal operation, and introduces several technical implications and opens important questions as to what happens to each control requirement in case of adding numerous RESs to the existing generation portfolio, and to whether the traditional power system control approaches to operation in the new environment are still adequate.
When renewable power plants are introduced into the power system, an additional source of variation is added to the already variable nature of the system. To analyze the variations caused by RES units, the total effect is important, and every change in RES power output does not need to be matched one by one via a change in another generating unit moving in the opposite direction. However, as already mentioned, the slow RES power fluctuation dynamics and total average power variation may negatively contribute to the power imbalance, which should be taken into account in the new control schemes. Among all RESs, because of dynamic behavior and amount of penetration, the impact of wind power on the system performance is more significant than other types of renewable sources. Therefore, some control schemes may need a revision in the presence of high penetration wind turbines.
It is shown that the doubly fed induction generators (DFIGs) have larger loadability than the induction generators (IGs). Both stator and rotor windings of the IG type wind turbine generators are connected directly with the power grid, but in the DFIG type only stator is directly connected and the rotor is connected through a power electronic type converter. The IG type wind turbine generators in turn add more inertia than DFIG in the power system; and in conclusion, the IG type wind turbine generators' frequency response is better than systems with DFIG type, in the same conditions.
To study the impacts of different types of wind turbines on the voltage and frequency behavior, the IEEE nine-bus power system is considered as a test system [17]. A single diagram of the test system with wind farms is shown in Fig. 5.13. Simulation data and system parameters are given in Appendix B.
Figure 5.13 Nine-bus test system with two wind farms.
As a serious disturbance scenario, the largest generator (G2) in the test system is tripped at t = 10 s in the presence of the following conditions: without wind turbine, with 10% DFIG type penetration, with 10% IG type penetration, and with 10% IG type wind turbine compensated with a static compensator (STATCOM). Figure 5.14 shows the frequency and voltage responses following the mentioned disturbance. The rate of frequency change is also illustrated in this figure.
Figure 5.14 System response following G2 outage with and without WTGs: (a) frequency deviation and (b) voltages changes.
All of the four cases are unstable, but they show different frequency/voltage response behaviors. Here, to protect the system against blackout, an emergency control action may need to be applied at the first few seconds (following the disturbance). The difference between the four test scenarios is clearly demonstrated through the simulation results. It is also shown that the frequency and voltage responses may behave in opposite directions.
5.5.4 RESs Contribution to Regulation Services
Planning the required power reserve, concerning the rapid growth of variable renewable generation and the resulting impacts on power system performance also is an important issue in future power system operation and control. For example, consider a power system with a high penetration of wind power. A greater amount of power reserve is needed for a larger amount of fluctuating wind power to cover periods when there is no wind. On the other hand, managing surplus electricity during periods of strong wind could be also considered as a challenge. Contribution of a renewable power plant (e.g., wind farm) in the ancillary/regulation services to provide the regulation power reserve can be considered as a proper solution. In combination with advanced forecasting techniques, it is now possible to design variable generators with the full range of performance capability that is comparable, and in some cases superior, to conventional synchronous generators. For example, unlike a typical thermal power plant whose output ramps downward rather slowly, wind farms can react quickly to a dispatch instruction taking seconds, rather than minutes.
Therefore, variable generation resources, such as wind power facilities, can be equipped to provide governing and participate in regulation tasks as well as conventional generators. For example, in the near future, the RESs are needed to actively participate in frequency control issue and maintaining system reliability along with conventional generation. Figure 5.15 shows the frequency response model for such cooperation [11]. Here, renewable power plants (
,…, 
), such as wind farms that can provide a considerable amount of power, also participate in the frequency regulation system by producing regulation renewable power (
).
Figure 5.15 Frequency regulation with contribution of RESs.
Figure 5.15 shows a block diagram of a typical control area with n conventional and m renewable generating units. Here, 
is the frequency deviation, 
is the mechanical power, 
is the secondary frequency control action, 
is the load disturbance, 
is the equivalent inertia constant, 
is the equivalent damping coefficient, 
is the control frequency bias, 
is the drooping characteristic, 
is the primary frequency control action, 
is the participation factor, 
is the RES power fluctuation, ACE is the area control error, 
is the conventional governor-turbine model, and finally, 
and 
are the augmented local load change and tie-line power fluctuation signals, respectively. Here, for simplicity, the corresponding blocks for GRC, governor dead bands, and time delays (which are shown in Fig. 5.6) as well as the detailed dynamics of renewable power plants are not indicated in Fig. 5.15.
Similar to conventional generating units, the participation factor for each power plant is determined by market operator. These power plants may use individual controllers, but those controllers should be coordinated together, as well as conventional ones. In new frequency response models, the ACE signal should represent the impacts of renewable power on the scheduled flow over the tie-line, as well as the local power fluctuation via the area frequency. According to Fig. 5.15, the updated ACE signal can be obtained as follows [11]:
where Ptie-C,act, Ptie-C,sched, Ptie-RES,act, and Ptie-RES,sched are actual conventional tie-line power, scheduled conventional tie-line power, actual RES tie-line power, and scheduled RES tie-line power, respectively. In addition to the wind turbines, other participants can also provide regulation services, such as storage devices that smooth either consumption or generation, consumers that can modulate their consumption upon request or automatically, and to some extent RESs. The demand for AGC services is defined by the market operator and depends on the power system structure.
5.6 Summary
This chapter provides an introduction on the general aspects of power system stability and control. Fundamental concepts and definitions of angle, voltage and frequency stability, and existing controls are emphasized. The timescales and characteristics of various power system controls are described. The SCADA/EMS architecture in modern power grids is explained. Finally, some challenges and new research directions are presented.
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