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The basic requirement for security analysis is to assess the impact of any possible contingency on system performance. For the purpose of setting planning and operating rules that will enable the system to be operated in a secure manner, it is necessary to consider all credible contingencies, different network configurations, and different operating points for given performance criteria. Hence, in the deterministic approach, these assessments may involve a large number of computer simulations even if there is a selection process at each stage of the analysis. The decision in that case is founded on the requirement that each outage event in a specified list, the contingency set, results in system performance that satisfies the criteria of the chosen performance evaluation. To handle these assessments for all possible situations by an exhaustive study is generally not reasonable. Since the resulting security rules may lead to the settlement and schedule of investment needs as well as operating rules, it is important to optimize the economical impact of security measures that have to be taken in order to be sure that there is no unnecessary or unjustified investment or operating costs. This has been the case for many years, since the emphasis was on the most severe, credible event leading to overly conservative solutions.

One way to deal with this problem is the concept of the probability of occurrence (contingencies) in the early stage of security analysis. This can be jointly used with a statistical approach that allows the generation of appropriate scenarios in order to fit more with the reality of the power system from the technical point of view as well as from the economical point view.

THE BASICS OF GENETIC ALGORITHMS

A genetic algorithm (GA) is a search algorithm often used in nonlinear discrete optimization problems. The development of GAs was inspired by the biological notion of evolution. Initially described by John Holland, they were popularized by David Goldberg who described the basic genetic algorithm very well. In a GA, data, initialized randomly in a data structure appropriate for the solution to the problem, evolves over time and becomes a suitable answer to the problem. An entire population of candidate solutions (data structures with a form suitable for solving for the problem being studied) is “randomly” initialized and evolves according to GA rules. The data structures often consist of strings of binary numbers that are mapped onto the solution space for evaluation. Each solution (often termed a creature) is assigned a fitness; a heuristic measure of its quality. During the evolutionary process, those creatures having higher fitness are favored in the parent selection process and are allowed to procreate.

The parent selection is essentially a random selection with a fitness bias. The type of fitness bias is determined by the parent selection method. Following the parent selection process, the processes of crossover and mutation are utilized and new creatures are developed that ideally explore a different area of the solution space. These new creatures replace less fit creatures from the existing population. Figure 12.11 shows a block diagram of the general GA.

FIGURE 12.11 A simple genetic algorithm.

ECONOMICAL GENERATION OPERATION

Since the introduction of electricity supply to the public in the late 1800s, people in many parts of the world have grown to expect an inexpensive reliable source of electricity. Providing that electric energy economically and efficiently requires the generation company to carefully control their generating units, and to consider many factors that may affect the performance, cost, and profitability of their operation.

The unit commitment and economic dispatch algorithms play an important part in deciding how to operate the electric generating units around the world. The introduction of competition has changed many of the factors considered in solving these problems. Furthermore, advancements in solution techniques offer a continuum of candidate algorithms, each having its own advantages and disadvantages.

Research continues to push these algorithms further. This chapter has provided the reader with an introduction to the problems of determining optimal unit commitment schedules and economic dispatches.

OPERATOR TRAINING SIMULATOR

Training simulators were originally created as generic systems for introducing operators to the electrical and dynamic behavior of power systems. Today, they model actual power systems with reasonable fidelity and are integrated with EMS to provide a realistic environment for operators and dispatchers to practice normal, every-day operating tasks and procedures as well as experience emergency operating situations.

The various training activities can be safely and conveniently practiced with the simulator responding in a manner similar to the actual power system.

An operator training simulator (OTS) can be used in an investigatory manner to recreate past actual operational scenarios and to formulate system restoration procedures. Scenarios can be created, saved, and reused. The OTS can be used to evaluate the functionality and performance of new real-time EMS functions and also for tuning AGC in an off-line, secure environment.

The OTS has three main subsystems (Fig. 12.4).

ENERGY CONTROL SYSTEM

The energy control system (ECS) emulates normal EMS functions and is the only part of the OTS with which the trainee interacts. It consists of the supervisory control and data acquisition (SCADA) system, generation control system, and all other EMS functions.

POWER SYSTEM DYNAMIC SIMULATION

This subsystem simulates the dynamic behavior of the power system. System frequency is simulated using the “long-term dynamics” system model, where frequency of all units is assumed to be the same. The prime-mover dynamics are represented by models of the units, turbines, governors, boilers, and boiler auxiliaries. The network flows and states (bus voltages and angles, topology, transformer taps, etc.) are calculated at periodic intervals. Relays are modeled, and they emulate the behavior of the actual devices in the field.

INSTRUCTIONAL SYSTEM

This subsystem includes the capabilities to start, stop, restart, and control the simulation. It also includes making save cases, retrieving save cases, reinitializing to a new time, and initializing to a specific real-time situation.

It is also used to define event schedules. Events are associated with both the power system simulation and the ECS functions. Events may be deterministic (occur at a predefined time), conditional (based on a predefined set of power system conditions being met), or probabilistic (occur at random).

FIGURE 12.4 OTS block diagram.

POWER SYSTEM SECURITY CONTROL

Power systems are designed to survive all probable contingencies. A contingency is defined as an event that causes one or more important components such as transmission lines, generators, and transformers to be unexpectedly removed from service. Survival means the system stabilizes and continues to operate at acceptable voltage and frequency levels without loss of load. Operations must deal with a vast number of possible conditions experienced by the system, many of which are not anticipated in planning. Instead of dealing with the impossible task of analyzing all possible system states, security control starts with a specific state: the current state if executing the real-time network sequence; a postulated state if executing a study sequence. Sequence means sequential execution of programs that perform the following steps:

1. Determine the state of the system based on either current or postulated conditions.

2. Process a list of contingencies to determine the consequences of each contingency on the system in its specified state.

3. Determine preventive or corrective action for those contingencies which represent unacceptable risk.

Real-time and study network analysis sequences are diagrammed in Fig. 12.3.

Security control requires topological processing to build network models and uses large-scale AC network analysis to determine system conditions. The required applications are grouped as a network subsystem that typically includes the following functions:

• Topology processor: Processes real-time status measurements to determine an electrical connectivity (bus) model of the power system network.

• State estimator: Uses real-time status and analog measurements to determine the ‘‘best’’ estimate of the state of the power system. It uses a redundant set of measurements; calculates voltages, phase angles, and power flows for all components in the system; and reports overload conditions.

• Power flow: Determines the steady-state conditions of the power system network for a specified generation and load pattern. Calculates voltages, phase angles, and flows across the entire system.

• Contingency analysis: Assesses the impact of a set of contingencies on the state of the power system and identifies potentially harmful contingencies that cause operating limit violations.

• Optimal power flow: Recommends controller actions to optimize a specified objective function (such as system operating cost or losses) subject to a set of power system operating constraints.

• Security enhancement: Recommends corrective control actions to be taken to alleviate an existing or potential overload in the system while ensuring minimal operational cost.

• Preventive action: Recommends control actions to be taken in a “preventive” mode before a contingency occurs to preclude an overload situation if the contingency were to occur.

• Bus load forecasting: Uses real-time measurements to adaptively forecast loads for the electrical connectivity (bus) model of the power system network.

• Transmission loss factors: Determines incremental loss sensitivities for generating units; calculates the impact on losses if the output of a unit were to be increased by 1 MW.

• Short-circuit analysis: Determines fault currents for single-phase and three-phase faults for fault locations across the entire power system network.

FIGURE 12.3 Real-time and study network analysis sequences.

ENERGY MANAGEMENT

Generation control and ED minimize the current cost of energy production and transmission within the range of available controls. Energy management is a supervisory layer responsible for economically scheduling production and transmission on a global basis and over time intervals consistent with cost optimization. For example, water stored in reservoirs of hydro plants is a resource that may be more valuable in the future and should, therefore, not be used now even though the cost of hydro energy is currently lower than thermal generation. The global consideration arises from the ability to buy and sell energy through the interconnected power system; it may be more economical to buy than to produce from plants under direct control. Energy accounting processes transaction information and energy measurements recorded during actual operation as the basis of payment for energy sales and purchases.

Energy management includes the following functions:

• System load forecast: Forecasts system energy demand each hour for a specified forecast period of 1 to 7 days.

• Unit commitment: Determines start-up and shut-down times for most economical operation of thermal generating units for each hour of a specified period of 1 to 7 days.

• Fuel scheduling: Determines the most economical choice of fuel consistent with plant requirements, fuel purchase contracts, and stockpiled fuel.

• Hydro-thermal scheduling: Determines the optimum schedule of thermal and hydro energy production for each hour of a study period up to 7 days while ensuring that hydro and thermal constraints are not violated.

• Transaction evaluation: Determines the optimal incremental and production costs for exchange (purchase and sale) of additional blocks of energy with neighboring companies.

• Transmission loss minimization: Recommends controller actions to be taken in order to minimize overall power system network losses.

• Security constrained dispatch: Determines optimal outputs of generating units to minimize production cost while ensuring that a network security constraint is not violated.

• Production cost calculation: Calculates actual and economical production costs for each generating unit on an hourly basis.

ELECTRIC LOAD MANAGEMENT

SCADA, with its relatively expensive RTUs installed at distribution substations, can provide status and measurements for distribution feeders at the substation. Distribution automation equipment is now available to measure and control at locations dispersed along distribution circuits. This equipment can monitor sectionalizing devices (switches, interrupters, fuses), operate switches for circuit reconfiguration, control voltage, read customers’ meters, implement time-dependent pricing (on-peak, off-peak rates), and switch customer equipment to manage load. This equipment requires significantly increased functionality at distribution control centers.

Distribution control center functionality varies widely from company to company, and the following list is evolving rapidly.

• Data acquisition: Acquires data and gives the operator control over specific devices in the field, Includes data processing, quality checking, and storage.

• Feeder switch control: Provides remote control of feeder switches.

• Tagging and alarms: Provides features similar to SCADA.

• Diagrams and maps: Retrieves and displays distribution maps and drawings. Supports device selection from these displays. Overlays telemetered and operator-entered data on displays.

• Preparation of switching orders: Provides templates and information to facilitate preparation of instructions necessary to disconnect, isolate, reconnect, and reenergize equipment.

• Switching instructions: Guides operator through execution of previously prepared switching orders.

• Trouble analysis: Correlates data sources to assess scope of trouble reports and possible dispatch of work crews.

• Fault location: Analyzes available information to determine scope and location of fault.

• Service restoration: Determines the combination of remote control actions that will maximize restoration of service. Assists operator to dispatch work crews.

• Circuit continuity analysis: Analyzes circuit topology and device status to show electrically connected circuit segments (either energized or de-energized).

• Power factor and voltage control: Combines substation and feeder data with predetermined operating parameters to control distribution circuit power factor and voltage levels.

• Electrical circuit analysis: Performs circuit analysis, single-phase or three-phase, balanced or unbalanced.

• Load management: Controls customer loads directly through appliance switching (e.g., water heaters) and indirectly through voltage control.

• Meter reading: Reads customer’s meters for billing, peak demand studies, time of use tariffs. Provides remote connect/disconnect.

AUTOMATIC GENERATION CONTROL

Automatic generation control (AGC) consists of two major and several minor functions that operate online in real-time to adjust the generation against load at minimum cost. The major functions are load frequency control and economic dispatch, each of which is described below. The minor functions are reserve monitoring, which assures enough reserve on the system; interchange scheduling, which initiates and completes scheduled interchanges; and other similar monitoring and recording functions.

LOAD FREQUENCY CONTROL

Load frequency control (LFC) has to achieve three primary objectives, which are stated below in priority order:

1. To maintain frequency at the scheduled value
2. To maintain net power interchanges with neighboring control areas at the scheduled values
3. To maintain power allocation among units at economically desired values

The first and second objectives are met by monitoring an error signal, called area control error (ACE), which is a combination of net interchange error and frequency error and represents the power imbalance between generation and load at any instant. This ACE must be filtered or smoothed such that excessive and random changes in ACE are not translated into control action. Since these excessive changes are different for different systems, the filter parameters have to be tuned specifically for each control area.

The filtered ACE is then used to obtain the proportional plus integral control signal. This control signal is modified by limiters, dead-bands, and gain constants that are tuned to the particular system. This control signal is then divided among the generating units under control by using participation factors to obtain unit control errors (UCE).

These participation factors may be proportional to the inverse of the second derivative of the cost of unit generation so that the units would be loaded according to their costs, thus meeting the third objective.

However, cost may not be the only consideration because the different units may have different response rates and it may be necessary to move the faster generators more to obtain an acceptable response. The UCEs are then sent to the various units under control and the generating units monitored to see that the corrections take place. This control action is repeated every 2 to 6 s.

In spite of the integral control, errors in frequency and net interchange do tend to accumulate over time. These time errors and accumulated interchange errors have to be corrected by adjusting the controller settings according to procedures agreed upon by the whole interconnection. These accumulated errors as well as ACE serve as performance measures for LFC.

The main philosophy in the design of LFC is that each system should follow its own load very closely during normal operation, while during emergencies, each system should contribute according to its relative size in the interconnection without regard to the locality of the emergency. Thus, the most important factor in obtaining good control of a system is its inherent capability of following its own load. This is guaranteed if the system has adequate regulation margin as well as adequate response capability. Systems that have mainly thermal generation often have difficulty in keeping up with the load because of the slow response of the units.

The design of the controller itself is an important factor, and proper tuning of the controller parameters is needed to obtain “good” control without “excessive” movement of units. Tuning is system-specific, and although system simulations are often used as aids, most of the parameter adjustments are made in the field using heuristic procedures.

ECONOMIC DISPATCH

Since all the generating units that are online have different costs of generation, it is necessary to find the generation levels of each of these units that would meet the load at the minimum cost. This has to take into account the fact that the cost of generation in one generator is not proportional to its generation level but is a nonlinear function of it. In addition, since the system is geographically spread out, the transmission losses are dependent on the generation pattern and must be considered in obtaining the optimum pattern.

Certain other factors have to be considered when obtaining the optimum generation pattern. One is that the generation pattern provides adequate reserve margins. This is often done by constraining the generation level to a lower boundary than the generating capability. A more difficult set of constraints to consider are the transmission limits. Under certain real-time conditions it is possible that the most economic pattern may not be feasible because of unacceptable line flows or voltage conditions. The present-day economic dispatch (ED) algorithm cannot handle these security constraints. However, alternative methods based on optimal power flows have been suggested but have not yet been used for real-time dispatch.

The minimum cost dispatch occurs when the incremental cost of all the generators is equal. The cost functions of the generators are nonlinear and discontinuous. For the equal marginal cost algorithm to work, it is necessary for them to be convex. These incremental cost curves are often represented as monotonically increasing piecewise-linear functions. A binary search for the optimal marginal cost is conducted by summing all the generation at a certain marginal cost and comparing it with the total power demand. If the demand is higher, a higher marginal cost is needed, and vice versa. This algorithm produces the ideal setpoints for all the generators for that particular demand, and this calculation is done every few minutes as the demand changes.

The losses in the power system are a function of the generation pattern, and they are taken into account by multiplying the generator incremental costs by the appropriate penalty factors. The penalty factor for each generator is a reflection of the sensitivity of that generator to system losses, and these sensitivities can be obtained from the transmission loss factors.

This ED algorithm generally applies to only thermal generation units that have cost characteristics of the type discussed here. The hydro units have to be dispatched with different considerations. Although there is no cost for the water, the amount of water available is limited over a period, and the displacement of fossil fuel by this water determines its worth. Thus, if the water usage limitation over a period is known, say from a previously computed hydro optimization, the water worth can be used to dispatch the hydro units.

LFC and the ED functions both operate automatically in real-time but with vastly different time periods.

Both adjust generation levels, but LFC does it every few seconds to follow the load variation, while ED does it every few minutes to assure minimal cost. Conflicting control action is avoided by coordinating the control errors. If the unit control errors from LFC and ED are in the same direction, there is no conflict. Otherwise, logic is set to either follow load (permissive control) or follow economics (mandatory control).

RESERVE MONITORING

Maintaining enough reserve capacity is required in case generation is lost. Explicit formulas are followed to determine the spinning (already synchronized) and ready (10 min) reserves required. The availability can be assured by the operator manually, or, as mentioned previously, the ED can also reduce the upper dispatch able limits of the generators to keep such generation available.

INTERCHANGE TRANSACTION SCHEDULING

The contractual exchange of power between utilities has to be taken into account by the LFC and ED functions. This is done by calculating the net interchange (sum of all the buy and sale agreements) and adding this to the generation needed in both the LFC and ED. Since most interchanges begin and end on the hour, the net interchange is ramped from one level to the new over a 10- or 20-min period straddling the hour. The programs achieve this automatically from the list of scheduled transactions.

COMMON TRAITS OF GOOD ENGINEERS

Although the activities of engineers are quite varied, there are some personality traits and work habits that typify most of today’s successful engineers.

• Engineers are problem solvers.

• Good engineers have a firm grasp of the fundamental principles of engineering, which they can use to solve many different problems.

• Good engineers are analytical, detailed oriented, and creative.

• Good engineers have a desire to be lifelong learners. For example, they take continuing education classes, seminars, and workshops to stay abreast of innovations and new technologies.

This is particularly important in today’s world because the rapid changes in technology will require you as an engineer to keep pace with new technologies. Moreover, you will risk being laid off or denied promotion if you are not continually improving your engineering education.

• Good engineers, regardless of their area of specialization, have a core knowledge that can be applied to many areas. Therefore, well-trained engineers are able to work outside their area of specialization in other related fields. For example, a good mechanical engineer with a well rounded knowledge base can work as an automotive engineer, an aerospace engineer, or as a chemical engineer.

• Good engineers have written and oral communication skills that equip them to work well with their colleagues and to convey their expertise to a wide range of clients.

• Good engineers have time-management skills that enable them to work productively and efficiently.

• Good engineers have good “people skills” that allow them to interact and communicate effectively with various people in their organization. For example, they are able to communicate equally well with the sales and marketing experts and their own colleagues.

• Engineers are required to write reports. These reports might be lengthy, detailed technical reports containing graphs, charts, and engineering drawings, or they may take the form of brief memoranda or executive summaries.

• Engineers are adept at using computers in many different ways to model and analyze various practical problems.

• Good engineers actively participate in local and national discipline-specific organizations by attending seminars, workshops, and meetings. Many even make presentations at professional meetings.

• Engineers generally work in a team environment where they consult each other to solve complex problems. They divide up the task into smaller, manageable problems among themselves; consequently, productive engineers must be good team players. Good interpersonal and communication skills are increasingly important now because of the global market. For example, various parts of a car could be made by different companies located in different countries. In order to ensure that all components fit and work well together, cooperation and coordination are essential, which demands strong communication skills.

Clearly, an interest in building things or taking things apart or solving puzzles is not all that is required to become an engineer. In addition to having a dedication to learning and a desire to find solutions, an engineer needs to foster certain attitudes and personality traits.

These are some other facts about engineering that are worth noting.

• For almost all entry-level engineering jobs, a bachelor’s degree in engineering is required.

According to the U.S. Bureau of Labor Statistics:

• The starting salaries of engineers are significantly higher than those of bachelor’s-degree graduates in other fields. The outlook for engineering is very good. Good employment opportunities are expected for new engineering graduates during 2010 –2018.

• Most engineering degrees are granted in electrical, mechanical, and civil engineering, the parents of all other engineering branches.

WHAT IS ENGINEERING AND WHAT DO ENGINEERS HAVE TO DO?

Engineers apply physical and chemical laws and principles and mathematics to design millions of products and services that we use in our everyday lives. These products include cars, computers, aircraft, clothing, toys, home appliances, surgical equipment, heating and cooling equipment, health care devices, tools and machines that makes various products, and so on.

Engineers consider important factors such as cost, efficiency, reliability, and safety when designing these products. Engineers perform tests to make certain that the products they design withstand various loads and conditions. They are continuously searching for ways to improve already existing products as well. They also design and supervise the construction of buildings, dams, highways, and mass transit systems and the construction of power plants that supply power to manufacturing companies, homes, and offices. Engineers play a significant role in the design and maintenance of a nation’s infrastructure, including communication systems, public utilities, and transportation. Engineers continuously develop new, advanced materials to make products lighter and stronger for different applications. They are also responsible for finding suitable ways to extract petroleum, natural gas, and raw materials from the earth, and they are involved in coming up with ways of increasing crop, fruit, and vegetable yields along with improving the safety of our food products.

The following represent some common careers for engineers. In addition to design, some engineers work as sales representatives for products, while others provide technical support and troubleshooting for customers of their products. Many engineers decide to become involved in sales and customer support, because their engineering background enables them to explain and discuss technical information and to assist with installation, operation, and maintenance of various products and machines. Not all engineers work for private industries; some work for federal, state, and local governments in various capacities. Engineers work in departments of agriculture, defense, energy, and transportation. Some engineers work for the National Aeronautics and Space Administration (NASA). As you can see, there are many satisfying and challenging jobs for engineers.

METHODS OF ANALYSIS OF TRANSIENT STABILITY

MODELING

The basic concepts of transient stability are based on highly simplified models. Practical power systems consist of large numbers of generators, transmission circuits, and loads.

For stability assessment, the power system is normally represented using a positive sequence model. The network is represented by a traditional positive sequence power flow model that defines the transmission topology, line reactances, connected loads and generation, and pre-disturbance voltage profile.

Generators can be represented with various levels of detail, selected based on such factors as length of simulation, severity of disturbance, and accuracy required. The most basic model for synchronous generators consists of a constant internal voltage behind a constant transient reactance, and the rotating inertia constant (H). This is the so-called classical representation that neglects a number of characteristics: the action of voltage regulators, variation of field flux linkage, the impact of the machine physical construction on the transient reactances for the direct and quadrature axis, the details of the prime mover or load, and saturation of the magnetic core iron. Historically, classical modeling was used to reduce computational burden associated with more detailed modeling, which is not generally a concern with today’s simulation software and computer hardware. However, it is still often used for machines that are very remote from a disturbance (particularly in very large system models) and where more detailed model data is not available.

In general, synchronous machines are represented using detailed models that capture the effects neglected in the classical model, including the influence of generator construction (damper windings, saturation, etc.), generator controls, (excitation systems including power system stabilizers, etc.), the prime mover dynamics, and the mechanical load. Loads, which are most commonly represented as static voltage and frequency-dependent components, may also be represented in detail by dynamic models that capture their speed torque characteristics and connected loads. There are a myriad of other devices, such as HVDC lines and controls and static VAR devices, which may require detailed representation. Finally, system protections are often represented. Models may also be included for line protections (such as mho distance relays), out-of-step protections, loss of excitation protections, or special protection schemes.

Although power system models may be extremely large, representing thousands of generators and other devices producing systems with tens of thousands of system states, efficient numerical methods combined with modern computing power have made time-domain simulation readily available in many commercially available computer programs. It is also important to note that the time frame in which transient instability occurs is usually in the range of 1 to 5 sec, so that simulation times need not be excessively long.

ANALYTICAL METHODS

To accurately assess the system response following disturbances, detailed models are required for all critical elements. The complete mathematical model for the power system consists of a large number of algebraic and differential equations, including

Generators stator algebraic equations
Generator rotor circuit differential equations
Swing equations
Excitation system differential equations
Prime mover and governing system differential equations
Transmission network algebraic equations
Load algebraic and differential equations

While considerable work has been done on direct methods of stability analysis in which stability is determined without explicitly solving the system differential equations, the most practical and flexible method of transient stability analysis is time-domain simulation using step-by-step numerical integration of the nonlinear differential equations. A variety of numerical integration methods are used, including explicit methods (such as Euler and Runge-Kutta methods) and implicit methods (such as the trapezoidal method). The selection of the method to be used largely depends on the stiffness of the system being analyzed. Implicit methods are generally better suited than explicit methods for systems in which time steps are limited by numerical stability rather than accuracy.

SIMULATION STUDIES

Modern simulation tools offer sophisticated modeling capabilities and advanced numerical solution methods. Although simulation tools differ somewhat, the basic requirements and functions are the same.

INPUT DATA:

1. POWER-FLOW: Defines system topology and initial operating state.

2. DYNAMIC DATA: Includes model types and associated parameters for generators, motors, protections, and other dynamic devices and their controls.

3. PROGRAM CONTROL DATA: Specifies such items as the type of numerical integration to use and time-step.

4. SWITCHING DATA: Includes the details of the disturbance to be applied. This includes the time at which the fault is applied, where the fault is applied, the type of fault and its fault impedance if required, the duration of the fault, the elements lost as a result of the fault, and the total length of the simulation.

5. SYSTEM MONITORING DATA: This specifies which quantities are to be monitored (output) during the simulation. In general, it is not practical to monitor all quantities because system models are large and recording all voltages, angles, flows, generator outputs, etc., at each integration time step would create an enormous volume. Therefore, it is common practice to define a limited set of parameters to be recorded.

OUTPUT DATA:

1. SIMULATION LOG: This contains a listing of the actions that occurred during the simulation. It includes a recording of the actions taken to apply the disturbance and reports on any operation of protections or controls, or any numerical difficulty encountered.

2. RESULTS OUTPUT: This is an ASCII or binary file that contains the recording of each monitored variable over the duration of the simulation. These results are examined, usually through a graphical plotting, to determine if the system remained stable and to assess the details of the dynamic behavior of the system.

FACTORS INFLUENCING TRANSIENT STABILITY

Many factors affect the transient stability of a generator in a practical power system from which few are discussed here.

THE POST-DISTURBANCE SYSTEM REACTANCE: The weaker the post-disturbance system, the lower P_max will be.

THE DURATION OF THE FAULT CLEARING TIME: The longer the fault is applied, the longer the rotor will be accelerated and the more kinetic energy will be gained. The more energy that is gained during acceleration, the more difficult it is to dissipate it during deceleration.

THE INERTIA OF THE GENERATOR: The higher the inertia, the slower the rate of change of angle and the less the kinetic energy gained during the fault.

THE GENERATOR INTERNAL VOLTAGE AND INFINITE BUS VOLTAGE: The lower these voltages, the lower P_maxwill be.

THE GENERATOR LOADING PRIOR TO THE DISTURBANCE: The higher the loading, the closer the unit will be to P_max, which means that during acceleration, it is more likely to become unstable.

THE GENERATOR INTERNAL REACTANCE: The lower the reactance, the higher the peak power and the lower the initial rotor angle.

THE GENERATOR OUTPUT DURING THE FAULT: This is a function of the fault location and type of fault.

TRANSIENT STABILITY CONSIDERATIONS IN SYSTEM DESIGN

Transient stability is an important consideration that must be dealt with during the design of power systems. In the design process, time-domain simulations are conducted to assess the stability of the system under various conditions and when subjected to various disturbances. Since it is not practical to design a system to be stable under all possible disturbances, design criteria specify the disturbances for which the system must be designed to be stable. The criteria disturbances generally consist of the more statistically probable events which could cause the loss of any system element and typically include three-phase faults cleared in normal time and line-to-ground faults with delayed clearing due to breaker failure. In most cases, stability is assessed for the loss of one element (such as a transformer or transmission circuit) with possibly one element out-of-service pre-disturbance.

Therefore, in system design, a wide number of disturbances are assessed and if the system is found to be unstable (or marginally stable); a variety of actions can be taken to improve stability. These include the following.

• REDUCTION OF TRANSMISSION SYSTEM REACTANCE: This can be achieved by adding additional parallel transmission circuits, providing series compensation on existing circuits, and by using transformers with lower leakage reactances.

• HIGH-SPEED FAULT CLEARING: In general, two-cycle breakers are used in locations where faults must be removed quickly to maintain stability. As the speed of fault clearing decreases, so does the amount of kinetic energy gained by the generators during the fault.

• DYNAMIC BRAKING: Shunt resistors can be switched in following a fault to provide an artificial electrical load. This increases the electrical output of the machines and reduces the rotor acceleration.

• REGULATE SHUNT COMPENSATION: By maintaining system voltages around the power system, the flow of synchronizing power between generators is improved.

• REACTOR SWITCHING: The internal voltages of generators, and therefore stability, can be increased by connected shunt reactors.

• SINGLE POLE SWITCHING: Most power system faults are of the single-line-to-ground type. However, in most schemes, this type of fault will trip all three phases. If single pole switching is used, only the faulted phase is removed and power can flow on the remaining two phases, thereby greatly reducing the impact of the disturbance.

• STEAM TURBINE FAST-VALVING: Steam valves are rapidly closed and opened to reduce the generator accelerating power in response to a disturbance.

• GENERATOR TRIPPING: Perhaps one of the oldest and most common methods of improving transient stability, this approach disconnects selected generators in response to a disturbance. This has the effect of reducing the power that is required to be transferred over critical transmission interfaces.

• HIGH-SPEED EXCITATION SYSTEMS: As illustrated by the simple examples presented earlier, increasing the internal voltage of a generator has the effect of improving transient stability. This can be achieved by fast-acting excitation systems that can rapidly boost field voltage in response to disturbances.

• SPECIAL EXCITATION SYSTEM CONTROLS: It is possible to design special excitation systems that can use discontinuous controls to provide special field boosting during the transient period, thereby improving stability.

• SPECIAL CONTROL OF HVDC LINKS: The DC power on HVDC links can be rapidly ramped up or down to assist in maintaining generation/load imbalances caused by disturbances. The effect is similar to generation or load tripping.

• CONTROLLED SYSTEM SEPARATION AND LOAD SHEDDING: Generally considered a last resort, it is often feasible to design system controls that can respond to separate, or island, a power system into areas with balanced generation and load. Some load shedding or generation tripping may also be required in selected islands. In the event of a disturbance, instability can be prevented from propagating and affecting large areas by partitioning the system in this manner. If instability primarily results in generation loss, load shedding alone may be sufficient to control the system.

TRANSIENT STABILITY CONSIDERATIONS IN SYSTEM OPERATION

While it is true that power systems are designed to be transiently stable, and many of the methods described above may be used to achieve this goal, in actual practice, systems may be prone to instability.

This is largely due to uncertainties related to assumptions made during the design process. These uncertainties result from a number of sources, including:

• LOAD AND GENERATION FORECAST: The design process must use forecast information about the amount, distribution, and characteristics of the connected loads, as well as the location and amount of connected generation. These all have a great deal of uncertainty. If the actual system load is higher than planned, the generation output will be higher, the system will be more stressed, and the transient stability limit may be significantly lower.

• SYSTEM TOPOLOGY: Design studies generally assume all elements in service, or perhaps up to two elements out of service. In actual systems, there are usually many elements out of service at any one time due to forced outages (failures) or system maintenance. Clearly, these outages can seriously weaken the system and make it less transiently stable.

• DYNAMIC MODELING: All models used for power system simulation, even the most advanced, contain approximations out of practical necessity.

• DYNAMIC DATA: The results of time-domain simulations depend heavily on the data used to represent the models for generators and the associated controls. In many cases this data is not known (typical data is assumed) or is in error (either because it has not been derived from field measurements or due to changes that have been made in the actual system controls that have not been reflected in the data).

• DEVICE OPERATION: In the design process it is assumed that controls and protection will operate as designed. In the actual system, relays, breakers, and other controls may fail or operate improperly.

To deal with these uncertainties in actual system operation, safety margins are used. Operational (short term) time-domain simulations are conducted using a system model that is more accurate (by accounting for elements out on maintenance, improved short-term load forecast, etc.) than the design model. Transient stability limits are computed using these models. The limits are generally in terms of maximum flows allowable over critical interfaces, or maximum generation output allowable from critical generating sources. Safety margins are then applied to these computed limits. This means that actual system operation is restricted to levels (interface flows or generation) below the stability limit by an amount equal to a defined safety margin.

In general, the margin is expressed in terms of a percentage of the critical flow or generation output. For example, operation procedure might be to define the operating limit as 10% below the stability limit.

CONSIDERATION OF STABILITY IN SYSTEM DESIGN AND OPERATION

For reliable service, a power system must remain intact and be capable of withstanding a wide variety of disturbances. Owing to economic and technical limitations, no power system can be stable for all possible disturbances or contingencies. In practice, power systems are designed and operated so as to be stable for a selected list of contingencies, normally referred to as “design contingencies”.

Experience dictates their selection. The contingencies are selected on the basis that they have a significant probability of occurrence and a sufficiently high degree of severity, given the large number of elements comprising the power system. The overall goal is to strike a balance between costs and benefits of achieving a selected level of system security.

While security is primarily a function of the physical system and its current attributes, secure operation is facilitated by:

Proper selection and deployment of preventive and emergency controls.
Assessing stability limits and operating the power system within these limits.

Security assessment has been historically conducted in an off-line operation planning environment in which stability for the near-term forecasted system conditions is exhaustively determined. The results of stability limits are loaded into look-up tables which are accessed by the operator to assess the security of a prevailing system operating condition.

In the new competitive utility environment, power systems can no longer be operated in a very structured and conservative manner; the possible types and combinations of power transfer transactions may grow enormously. The present trend is, therefore, to use online dynamic security assessment. This is feasible with today’s computer hardware and stability analysis software.

CLASSIFICATION OF POWER SYSTEM STABILITY

NEED FOR CLASSIFICATION

Power system stability is a single problem; however, it is impractical to deal with it as such. Instability of the power system can take different forms and is influenced by a wide range of factors. Analysis of stability problems, including identifying essential factors that contribute to instability and devising methods of improving stable operation is greatly facilitated by classification of stability into appropriate categories. These are based on the following considerations:

• The physical nature of the resulting instability related to the main system parameter in which instability can be observed.

• The size of the disturbance considered indicates the most appropriate method of calculation and prediction of stability.

• The devices, processes, and the time span that must be taken into consideration in order to determine stability.

Figure 11.1 shows a possible classification of power system stability into various categories and subcategories.

FIGURE 11.1 Classification of power system stability.

The following are descriptions of the corresponding forms of stability phenomena.

A) ROTOR ANGLE STABILITY

Rotor angle stability is concerned with the ability of interconnected synchronous machines of a power system to remain in synchronism under normal operating conditions and after being subjected to a disturbance.

It depends on the ability to maintain/restore equilibrium between electromagnetic torque and mechanical torque of each synchronous machine in the system. Instability that may result occurs in the form of increasing angular swings of some generators leading to their loss of synchronism with other generators.

The rotor angle stability problem involves the study of the electromechanical oscillations inherent in power systems. A fundamental factor in this problem is the manner in which the power outputs of its rotor relative to that of the slower machine will advance. The resulting angular difference transfers part of the load from the slow machine to the fast machine, depending on the power angle relationship. This tends to reduce the speed difference and hence the angular separation. The power angle relationship, as discussed above, is highly nonlinear. Beyond a certain limit, an increase in angular separation is accompanied by a decrease in power transfer; this increases the angular separation further and leads to instability. For any given situation, the stability of the system depends on whether or not the deviations in angular positions of the rotors result in sufficient restoring torques.

It should be noted that loss of synchronism can occur between one machine and the rest of the system, or between groups of machines, possibly with synchronism maintained within each group after separating from each other.

The change in electrical torque of a synchronous machine following a perturbation can be resolved into two components:

• SYNCHRONIZING TORQUE COMPONENT: in phase with a rotor angle perturbation.

• DAMPING TORQUE COMPONENT: in phase with the speed deviation.

System stability depends on the existence of both components of torque for each of the synchronous machines. Lack of sufficient synchronizing torque results in aperiodic or non-oscillatory instability, whereas lack of damping torque results in oscillatory instability.

For convenience in analysis and for gaining useful insight into the nature of stability problems, it is useful to characterize rotor angle stability in terms of the following two categories:

1. SMALL SIGNAL (OR STEADY STATE) STABILITY

It is concerned with the ability of the power system to maintain synchronism under small disturbances. The disturbances are considered to be sufficiently small that linearization of system equations is permissible for purposes of analysis. Such disturbances are continually encountered in normal system operation, such as small changes in load.

Small signal stability depends on the initial operating state of the system. Instability that may result can be of two forms: (i) increase in rotor angle through a non-oscillatory or aperiodic mode due to lack of synchronizing torque, or (ii) rotor oscillations of increasing amplitude due to lack of sufficient damping torque.

In today’s practical power systems, small signal stability is largely a problem of insufficient damping of oscillations. The time frame of interest in small-signal stability studies is on the order of 10 to 20 s following a disturbance.

2. LARGE DISTURBANCE ROTOR ANGLE STABILITY OR TRANSIENT STABILITY

As it is commonly referred to, is concerned with the ability of the power system to maintain synchronism when subjected to a severe transient disturbance. The resulting system response involves large excursions of generator rotor angles and is influenced by the nonlinear power-angle relationship.

Transient stability depends on both the initial operating state of the system and the severity of the disturbance. Usually, the disturbance alters the system such that the post-disturbance steady state operation will be different from that prior to the disturbance. Instability is in the form of aperiodic drift due to insufficient synchronizing torque, and is referred to as first swing stability.

In large power systems, transient instability may not always occur as first swing instability associated with a single mode; it could be as a result of increased peak deviation caused by superposition of several modes of oscillation causing large excursions of rotor angle beyond the first swing.

The time frame of interest in transient stability studies is usually limited to 3 to 5 sec following the disturbance. It may extend to 10 sec for very large systems with dominant inter-area swings.

Power systems experience a wide variety of disturbances. It is impractical and uneconomical to design the systems to be stable for every possible contingency. The design contingencies are selected on the basis that they have a reasonably high probability of occurrence. As identified in Fig. 11.1, small signal stability as well as transient stability are categorized as short term phenomena.

B) VOLTAGE STABILITY

Voltage stability is concerned with the ability of a power system to maintain steady voltages at all buses in the system under normal operating conditions, and after being subjected to a disturbance. Instability that may result occurs in the form of a progressive fall or rise of voltage of some buses. The possible outcome of voltage instability is loss of load in the area where voltages reach unacceptably low values, or a loss of integrity of the power system.

Progressive drop in bus voltages can also be associated with rotor angles going out of step. For example, the gradual loss of synchronism of machines as rotor angles between two groups of machines approach or exceed 180° would result in very low voltages at intermediate points in the network close to the electrical center. In contrast, the type of sustained fall of voltage that is related to voltage instability occurs where rotor angle stability is not an issue.

The main factor contributing to voltage instability is usually the voltage drop that occurs when active and reactive power flow through inductive reactances associated with the transmission network; this limits the capability of transmission network for power transfer. The power transfer limit is further limited when some of the generators hit their reactive power capability limits. The driving force for voltage instability are the loads; in response to a disturbance, power consumed by the loads tends to be restored by the action of distribution voltage regulators, tap changing transformers, and thermostats.

Restored loads increase the stress on the high voltage network causing more voltage reduction. A rundown situation causing voltage instability occurs when load dynamics attempts to restore power consumption beyond the capability of the transmission system and the connected generation.

As in the case of rotor angle stability, it is useful to classify voltage stability into the following subcategories:

1. LARGE DISTURBANCE VOLTAGE STABILITY

It is concerned with a system’s ability to control voltages following large disturbances such as system faults, loss of generation, or circuit contingencies. This ability is determined by the system-load characteristics and the interactions of both continuous and discrete controls and protections. Determination of large disturbance stability requires the examination of the nonlinear dynamic performance of a system over a period of time sufficient to capture the interactions of such devices as under-load transformer tap changers and generator field-current limiters. The study period of interest may extend from a few seconds to tens of minutes. Therefore, long term dynamic simulations are required for analysis.

2. SMALL DISTURBANCE VOLTAGE STABILITY

It is concerned with a system’s ability to control voltages following small perturbations such as incremental changes in system load. This form of stability is determined by the characteristics of loads, continuous controls, and discrete controls at a given instant of time.

This concept is useful in determining, at any instant, how the system voltage will respond to small system changes. The basic processes contributing to small disturbance voltage instability are essentially of a steady state nature. Therefore, static analysis can be effectively used to determine stability margins, identify factors influencing stability, and examine a wide range of system conditions and a large number of post-contingency scenarios. A criterion for small disturbance voltage stability is that, at a given operating condition for every bus in the system, the bus voltage magnitude increases as the reactive power injection at the same bus is increased. A system is voltage unstable if, for at least one bus in the system, the bus voltage magnitude (V) decreases as the reactive power injection (Q) at the same bus is increased. In other words, a system is voltage stable if V-Q sensitivity is positive for every bus and unstable if V-Q sensitivity is negative for at least one bus.

The time frame of interest for voltage stability problems may vary from a few seconds to tens of minutes. Therefore, voltage stability may be either a short-term or a long-term phenomenon.

Voltage instability does not always occur in its pure form. Often, the rotor angle instability and voltage instability go hand in hand. One may lead to the other, and the distinction may not be clear. However, distinguishing between angle stability and voltage stability is important in understanding the underlying causes of the problems in order to develop appropriate design and operating procedures.

C) FREQUENCY STABILITY

Frequency stability is concerned with the ability of a power system to maintain steady frequency within a nominal range following a severe system upset resulting in a significant imbalance between generation and load. It depends on the ability to restore balance between system generation and load, with minimum loss of load.

Severe system upsets generally result in large excursions of frequency, power flows, voltage, and other system variables, thereby invoking the actions of processes, controls, and protections that are not modeled in conventional transient stability or voltage stability studies. These processes may be very slow, such as boiler dynamics, or only triggered for extreme system conditions, such as volts/hertz protection tripping generators. In large interconnected power systems, this type of situation is most commonly associated with islanding. Stability in this case is a question of whether or not each island will reach an acceptable state of operating equilibrium with minimal loss of load. It is determined by the overall response of the island as evidenced by its mean frequency, rather than relative motion of machines. Generally, frequency stability problems are associated with inadequacies in equipment responses, poor coordination of control and protection equipment, or insufficient generation reserve.

Over the course of frequency instability, the characteristic times of the processes and devices that are activated by the large shifts in frequency and other system variables will range from a matter of seconds, corresponding to the responses of devices such as generator controls and protections, to several minutes, corresponding to the responses of devices such as prime mover energy supply systems and load voltage regulators.

Although frequency stability is impacted by fast as well as slow dynamics, the overall time frame of interest extends to several minutes. Therefore, it is categorized as a long-term phenomenon in Fig. 11.1.

POWER SYSTEM STABILITY

Power system stability is the ability of the system, for a given initial operating condition, to regain a normal state of equilibrium after being subjected to a disturbance. Stability is a condition of equilibrium between opposing forces; instability results when a disturbance leads to a sustained imbalance between the opposing forces.

The power system is a highly nonlinear system that operates in a constantly changing environment; loads, generator outputs, topology, and key operating parameters change continually. When subjected to a transient disturbance, the stability of the system depends on the nature of the disturbance as well as the initial operating condition. The disturbance may be small or large. Small disturbances in the form of load changes occur continually, and the system adjusts to the changing conditions. The system must be able to operate satisfactorily under these conditions and successfully meet the load demand. It must also be able to survive numerous disturbances of a severe nature, such as a short-circuit on a transmission line or loss of a large generator.

Following a transient disturbance, if the power system is stable, it will reach a new equilibrium state with practically the entire system intact; the actions of automatic controls and possibly human operators will eventually restore the system to normal state. On the other hand, if the system is unstable, it will result in a run-away or run-down situation; for example, a progressive increase in angular separation of generator rotors, or a progressive decrease in bus voltages. An unstable system condition could lead to cascading outages and a shut-down of a major portion of the power system.

The response of the power system to a disturbance may involve much of the equipment. For instance, a fault on a critical element followed by its isolation by protective relays will cause variations in power flows, network bus voltages, and machine rotor speeds; the voltage variations will actuate both generator and transmission network voltage regulators; the generator speed variations will actuate prime mover governors; and the voltage and frequency variations will affect the system loads to varying degrees depending on their individual characteristics. Further, devices used to protect individual equipment may respond to variations in system variables and thereby affect the power system performance. A typical modern power system is thus a very high-order multivariable process whose dynamic performance is influenced by a wide array of devices with different response rates and characteristics. Hence, instability in a power system may occur in many different ways depending on the system topology, operating mode, and the form of the disturbance.

Traditionally, the stability problem has been one of maintaining synchronous operation. Since power systems rely on synchronous machines for generation of electrical power, a necessary condition for satisfactory system operation is that all synchronous machines remain in synchronism or, colloquially, “in step.” This aspect of stability is influenced by the dynamics of generator rotor angles and power-angle relationships.

Instability may also be encountered without the loss of synchronism. For example, a system consisting of a generator feeding an induction motor can become unstable due to collapse of load voltage. In this instance, it is the stability and control of voltage that is the issue, rather than the maintenance of synchronism. This type of instability can also occur in the case of loads covering an extensive area in a large system.

In the event of a significant load/generation mismatch, generator and prime mover controls become important, as well as system controls and special protections. If not properly coordinated, it is possible for the system frequency to become unstable, and generating units and/or loads may ultimately be tripped possibly leading to a system blackout. This is another case where units may remain in synchronism (until tripped by such protections as under-frequency), but the system becomes unstable.

Because of the high dimensionality and complexity of stability problems, it is essential to make simplifying assumptions and to analyze specific types of problems using the right degree of detail of system representation. The following subsection describes the classification of power system stability into different categories.

NATURE OF POWER SYSTEM OSCILLATIONS

• Oscillations are due to natural modes of the system and therefore cannot be eliminated. However, their damping and frequency can be modified.

• As power systems evolve, the frequency and damping of existing modes change and new ones may emerge.

• The source of “negative” damping is power system controls, primarily excitation system automatic voltage regulators.

• Interarea oscillations are associated with weak transmission links and heavy power transfers.

• Interarea oscillations often involve more than one utility and may require the cooperation of all to arrive at the most effective and economical solution.

• Power system stabilizers are the most commonly used means of enhancing the damping of interarea modes.

• Continual study of the system is necessary to minimize the probability of poorly damped oscillations. Such “beforehand” studies may have avoided many of the problems experienced in power systems..

It must be clear that avoidance of oscillations is only one of many aspects that should be considered in the design of a power system and so must take its place in line along with economy, reliability, operational robustness, environmental effects, public acceptance, voltage and power quality, and certainly a few others that may need to be considered. Fortunately, it appears that many features designed to further some of these other aspects also have a strong mitigating effect in reducing oscillations. However, one overriding constraint is that the power system operating point must be stable with respect to oscillations.

MITIGATION OF VOLTAGE STABILITY PROBLEMS

The following methods can be used to mitigate voltage stability problems.

MUST-RUN GENERATION: Operate uneconomic generators to change power flows or provide voltage support during emergencies or when new lines or transformers are delayed.

SERIES CAPACITORS: Use series capacitors to effectively shorten long lines, thus decreasing the net reactive loss. In addition, the line can deliver more reactive power from a strong system at one end to one experiencing a reactive shortage at the other end.

SHUNT CAPACITORS: Though the heavy use of shunt capacitors can be part of the voltage stability problem, sometimes additional capacitors can also solve the problem by freeing “spinning reactive reserve” in generators. In general, most of the required reactive power should be supplied locally, with generators supplying primarily active power.

STATIC VAR COMPENSATORS (SVC): SVCs, the modern counterpart to the synchronous condenser, are effective in controlling voltage and preventing voltage collapse, but have very definite limitations that must be recognized. Voltage collapse is likely in systems heavily dependent on SVCs when a disturbance exceeding planning criteria takes SVCs to ceiling.

OPERATE AT HIGHER VOLTAGES: Operating at higher voltage may not increase reactive reserves, but does decrease reactive demand. As such, it can help keep generators away from reactive power limits, and thus help operators maintain control of voltage. The comparison of receiving end Q–V curves for two sending end voltages shows the value of higher voltages.

UNDER-VOLTAGE LOAD SHEDDING: A small load reduction, even 5 to 10%, can make the difference between collapse and survival. Manual load shedding is used today for this purpose (some utilities use distribution voltage reduction via SCADA), though it may be too slow to be effective in the case of a severe reactive shortage. Inverse-time under-voltage relays are not widely used, but can be very effective. In a radial load situation, load shedding should be based on primary side voltage. In a steady-state stability problem, the load shed in the receiving system will be most effective even though voltages may be lowest near the electrical center (though shedding load in the vicinity of the lowest voltage may be more easily accomplished, and will be helpful).

LOWER POWER FACTOR GENERATORS: Where new generation is close enough to reactive-short areas or areas that may occasionally demand large reactive reserves, a .80 or .85 power factor generator may sometimes be appropriate. However, shunt capacitors with a higher power factor generator having reactive overload capability, may be more flexible and economic.

USE GENERATOR REACTIVE OVERLOAD CAPABILITY: Generators should be used as effectively as possible. Overload capability of generators and exciters may be used to delay voltage collapse until operators can change dispatch or curtail load when reactive overloads are modest. To be most useful, reactive overload capability must be defined in advance, operators trained in its use, and protective devices set so as not to prevent its use.

REASONS FOR GROUNDING

By Engr. Aneel Kumar May 27, 2014 No comments:

There are three basic reasons for grounding a power system which are personal safety, protective device operation, and noise control. All three of these reasons will be addressed.

PERSONAL SAFETY:

The most important reason for grounding a device on a power system is personal safety. The safety ground, as it is sometimes called, is provided to reduce or eliminate the chance of a high touch potential if a fault occurs in a piece of electrical equipment. Touch potential is defined as the voltage potential between any two conducting materials that can be touched simultaneously by an individual or animal. Figure 15.2 illustrates a dangerous touch potential situation. The “hot” conductor in the piece of equipment has come in contact with the case of the equipment. Under normal conditions, with the safety ground intact, the protective device would operate when this condition occurred. However, in Fig. 15.2, the safety ground is missing. This allows the case of the equipment to float above ground since the case of the equipment is not grounded through its base. In other words, the voltage potential between the equipment case and ground is the same as the voltage potential between the hot leg and ground. If the operator would come in contact with the case and ground (the floor), serious injury could result.

In recent years, manufacturers of handheld equipment, drills, saws, hair dryers, etc. have developed double insulated equipment. This equipment generally does not have a safety ground. However, there is never any conducting material for the operator to contact and therefore there is no touch potential hazard. If the equipment becomes faulted, the case or housing of the equipment is not energized.

PROTECTIVE DEVICE OPERATION:

As mentioned in the previous section, there must be a path for fault current to return to the source if protective devices are to operate during fault conditions. The National Electric Code (NEC) requires that an effective grounding path must be mechanically and electrically continuous (NEC 250-51), have the capacity to carry any fault currents imposed on it without damage (NEC 250-75). The NEC also states that the ground path must have sufficiently low impedance to limit the voltage and facilitate protective device operation. Finally, the earth cannot serve as the equipment-grounding path (NEC-250-91(c)).

The formula to determine the maximum circuit impedance for the grounding path is:

Table 15.1 gives examples of maximum ground path circuit impedances required for proper protective device operation.

NOISE CONTROL:

Noise control is the third main reason for grounding. Noise is defined as unwanted voltages and currents on a grounding system. This includes signals from all sources whether it is radiated or conducted. As stated, the primary reason for grounding is safety and is regulated by the NEC and local codes. Any changes to the grounding system to improve performance or eliminate noise control must be in addition to the minimum NEC requirements.

When potential differences occur between different grounding systems, insulation can be stressed and circulating currents can be created in low voltage cables (e.g., communications cables). In today’s electrical environment, buildings that are separated by large physical distances are typically tied together via a communication circuit. An example of this would be a college campus that may cover several square miles. Each building has its own grounding system. If these grounding systems are not tied together, a potential difference on the grounding circuit for the communication cable can occur. The idea behind grounding for noise control is to create an equi-potential grounding system, which in turn limits or even eliminates the potential differences between the grounding systems. If the there is an equi-potential grounding system and currents are injected into the ground system, the potential of the whole grounding system will rise and fall and potential differences will not occur.

Supplemental conductors, ground reference grids, and ground plates can all be used to improve the performance of the system as it relates to power quality. Optically isolated communications can also improve the performance of the system. By using the opto-isolators, connecting the communications to different ground planes is avoided. All improvements to the grounding system must be done in addition to the requirements for safety.

Separation of loads is another method used to control noise. Figure 15.3 illustrates this point. Figure 15.3 shows four different connection schemes. Each system from left to right improves noise control.

As seen in Figure 15.3, the best case would be the complete separation (system on the far right) of the ADP units from the motor loads and other equipment. Conversely, the worst condition is on the left of Fig. 15.3, where the ADP units are served from the same circuit as the motor loads.

TRADITIONAL SHUNT COMPENSATION

In general, shunt compensators are classified depending on the technology used in their implementation. Rotating and static equipments were commonly used to compensate reactive power and to stabilize power systems. In the last decades, a large number of different static FACTS controllers, using power electronic technologies and digital control schemes have been proposed and developed. There are two approaches to the realization of power electronics-based compensators: the one that employs thyristor-switched capacitors and reactors with tap-changing transformers, and the other group that uses self-commutated static converters. A brief description of the most commonly used shunt compensators is presented below.

FIXED OR MECHANICALLY SWITCHED CAPACITORS

Shunt capacitors were first employed for power factor correction in the year 1914. The leading current drawn by the shunt capacitors compensates the lagging current drawn by the load. The selection of shunt capacitors depends on many factors, the most important of which is the amount of lagging reactive power taken by the load. In the case of widely fluctuating loads, the reactive power also varies over a wide range. Thus, a fixed capacitor bank may often lead to either over-compensation or under compensation.

Variable VAR compensation is achieved using switched capacitors. Depending on the total VAR requirement, capacitor banks are switched into or switched out of the system. The smoothness of control is solely dependent on the number of capacitors switching units used. The switching is usually accomplished using relays and circuit breakers. However, these methods based on mechanical switches and relays have the disadvantage of being sluggish and unreliable. Also, they generate high inrush currents, and require frequent maintenance.

SYNCHRONOUS CONDENSERS

Synchronous condensers have played a major role in voltage and reactive power control for more than 50 years. Functionally, a synchronous condenser is simply a synchronous machine connected to the power system. After the unit is synchronized, the field current is adjusted to either generate or absorb reactive power as required by the ac system. The machine can provide continuous reactive power control when used with the proper automatic exciter circuit. Synchronous condensers have been used at both distribution and transmission voltage levels to improve stability and to maintain voltages within desired limits under varying load conditions and contingency situations. However, synchronous condensers are rarely used today because they require substantial foundations and a significant amount of starting and protective equipment. They also contribute to the short circuit current and they cannot be controlled fast enough to compensate rapid load changes. Moreover, their losses are much higher than those associated with static compensators, and the cost is much higher as well. Their advantage lies in their high temporary overload capability.

THYRISTORIZED VAR COMPENSATORS

As in the case of the synchronous condenser, the aim of achieving fine control over the entire VAR range, has been fulfilled with the development of static compensators but with the advantage of faster response times. Thyristorized VAR compensators consist of standard reactive power shunt elements (reactors and capacitors) which are controlled to provide rapid and variable reactive power. They can be grouped into two basic categories, the thyristor-switched capacitor (TSC) and the thyristor-controlled reactor (TCR).

PRINCIPLES OF SHUNT COMPENSATION

Figure 25.1 shows the principles and theoretical effects of shunt reactive power compensation in a basic ac system, which comprises a source V₁, a transmission line, and a typical inductive load. Figure 25.1 a shows the system without compensation, and its associated phasor diagram. In the phasor diagram, the phase angle of the current has been related to the load side, which means that the active current (I_P) is in phase with the load voltage V₂.

Since the load is assumed inductive, it requires reactive power for proper operation, which must be supplied by the source, increasing the current flow from the generator and through the lines. If reactive power is supplied near the load, the line current is minimized, reducing power losses and improving voltage regulation at the load terminals. This can be done with a capacitor, with a voltage source, or with a current source. In Fig. 25.1 b, a current-source device is being used to compensate the reactive component of the load current (I_Q). As a result, the system voltage regulation is improved and the reactive current component from the source is almost eliminated.

A current source or a voltage source can be used for reactive shunt compensation. The main advantages of using voltage or current source VAR generators (instead of inductors or capacitors) are that the reactive power generated is independent of the voltage at the point of connection and can be adjusted in a wide range.

Since shunt compensation is able to change the power flow in the system by varying the value of the applied shunt equivalent impedance, changing the reactive power flow in the system, during and following dynamic disturbances, the transient stability limit can be increased and effective power oscillation damping can be provided. Thereby, the voltage of the transmission line counteracts the accelerating swings of the disturbed machine and therefore damps the power oscillations.

Independent of the source type or system configuration, different requirements have to be taken into consideration for a successful operation of shunt compensators. Some of these requirements are simplicity, controllability, time response, cost, reliability, and harmonic distortion.


	FIGURE 25.1 Principles of shunt compensation in a	radial ac system. (a) System phasor diagram without	reactive compensation. (b) Shunt compensation of the	system with a current source.

SHUNT COMPENSATORS

Shunt compensation is used basically to control the amount of reactive power that flows through the power system. In a linear circuit, the reactive power is defined as the ac component of the instantaneous power, with a frequency equal to 100/120 Hz in a 50 or 60 Hz system. The reactive power generated by the ac power source is stored in a capacitor or a reactor during a quarter of a cycle, and in the next quarter cycle is sent back to the power source. The reactive power oscillates between the ac source and the capacitor or reactor, and also between them, at a frequency equal to two times the rated value (50 or 60 Hz). For this reason it can be compensated using static equipments or VAR generators, avoiding its circulation between the load (inductive or capacitive) and the source, and therefore improving voltage regulation and stability of the power system. Reactive power compensation can be implemented with VAR generators connected in parallel or in series.

HYBRID ACTIVE PASSIVE FILTERS

Figures 24.6, 24.7, and 24.8 show three types of hybrid active/passive filters, the main purpose of which is to reduce initial costs and to improve efficiency. The shunt passive filter consists of one or more tuned LC filters and/ or a high-pass filter. Table 24.2 shows comparisons among the three hybrid filters in which the active filters are different in function from the passive filters. Note that the hybrid filters are applicable to any current harmonic source, although a harmonic-producing load is represented by a thyristor rectifier with a DC link inductor in Figs. 24.6, 24.7, and 24.8.

Such a combination of a shunt active filter and a shunt passive filter as shown in Fig. 24.6 has already been applied to harmonic compensation of naturally-commutated twelve-pulse cycloconverters for steel mill drives. The passive filters absorbs 11th and 13th harmonic currents while the active filter compensates for 5th and 7th harmonic currents and achieves damping of harmonic resonance between the supply and the passive filter. One of the most import ant considerations in system design is to avoid competition for compensation between the passive filter and the active filter.

The hybrid active filters, shown in Fig. 24.7 and in Fig. 24.8 are rig ht now on the commercial stage, not only for harmonic compensation but also for harmonic isolation between supply and load, and for voltage regulation and imbalance compensation. They are considered prospective alternatives to pure active filters used alone.

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