A NEW APPROACH TO MULTIFUNCTIONAL DYNAMIC VOLTAGE RESTORER IMPLEMENTATION FOR EMERGENCY CONTROL IN DISTRIBUTION SYSTEMSABSTRACTThe dynamic voltage restorer (DVR) is one of the modern devices used in distribution systems to protect consumers against sudden changes in voltage amplitude. In this paper, emergency control in distribution systems is discussed by using the proposed multifunctional DVR control strategy. Also, the multiloop controller using the Posicast and P+Resonant controllers is proposed in order to improve the transient response and eliminate the steady-state error in DVR response, respectively. The proposed algorithm is applied to some disturbances in load voltage caused by induction motors starting, and a three-phase short circuit fault. Also, the capability of the proposed DVR has been tested to limit the downstream fault current. The current limitation will restore the point of common coupling (PCC) (the bus to which all feeders under study are connected) voltage and protect the DVR itself. The innovation here is that the DVR acts as virtual impedance with the main aim of protecting the PCC voltage during downstream fault without any problem in real power injection into the DVR. Simulation results show the capability of the DVR to control the emergency conditions of the distribution systems.

INTRODUCTIONVoltage sag and voltage swell are two of the most important power-quality (PQ) problems that encompass almost 80% of the distribution system PQ problems. According to the IEEE 19591995 standard, voltage sag is the decrease of 0.1to 0.9 p.u. in the rms voltage level at system frequency and with the duration of half a cycle to 1 min. Short circuits, starting large motors, sudden changes of load, and energization of transformers are the main causes of voltage sags.According to the definition and nature of voltage sag, it can be found that this is a transient phenomenon whose causes are classified as low- or medium-frequency transient events. In recent years, considering the use of sensitive devices in modern industries, different methods of compensation of voltage sags have been used. One of these methods is using the DVR to improve the PQ and compensate the load voltage.Previous works have been done on different aspects of DVR performance, and different control strategies have been found. These methods mostly depend on the purpose of using DVR. In some methods, the main purpose is to detect and compensate for the voltage sag with minimum DVR active power injection. Also, the in-phase compensation method can be used for sag and swell mitigation. The multiline DVR can be used for eliminating the battery in the DVR structure and controlling more than one line. Moreover, research has been made on using the DVR in medium level voltage. Harmonic mitigation and control of DVR under frequency variations are also in the area of research. The closed-loop control with load voltage and current feedback is introduced as a simple method to control the DVR. Also, Posicast and P+Resonant controllers can be used to improve the transient response and eliminate the steady-state error in DVR. The Posicast controller is a kind of step function with two parts and is used to improve the damping of the transient oscillations initiated at the start instant from the voltage sag. The P+Resonant controller consists of a proportional function plus a resonant function and it eliminates the steady-state voltage tracking error. The state feedforward and feedback methods, symmetrical components estimation, robust control, and wavelet transform have also been proposed as different methods of controlling the DVR.In all of the aforementioned methods, the source of disturbance is assumed to be on the feeder which is parallel to the DVR feeder. In this paper, a multifunctional control system is proposed in which the DVR protects the load voltage using Posicast and P+Resonant controllers when the source of disturbance is the parallel feeders. On the other hand, during a downstream fault, the equipment protects the PCC voltage, limits the fault current, and protects itself from large fault current. Although this latest condition has been described using the flux control method, the DVR proposed there acts like a virtual inductance with a constant value so that it does not receive any active power during limiting the fault current. But in the proposed method when the fault current passes through the DVR, it acts like series variable impedance ( where the equivalent impedance was a constant).The basis of the proposed control strategy in this paper is that when the fault current does not pass through the DVR, an outer feedback loop of the load voltage with an inner feedback loop of the filter capacitor current will be used. Also, a feedforward loop will be used to improve the dynamic response of the load voltage. Moreover, to improve the transient response, the Posicast controller and to eliminate the steady-state error, the P+Resonant controller are used. But in case the fault current passes through the DVR, using the flux control algorithm, the series voltage is injected in the opposite direction and, therefore, the DVR acts like series variable impedance.

VOLTAGE SAGVoltage sags and momentary power interruptions are probably the most important PQ problem affecting industrial and large commercial customers. These events are usually associated with a fault at some location in the supplying power system. Interruptions occur when the fault is on the circuit supplying the customer. But voltage sags occur even if the faults happen to be far away from the customer's site. Voltage sags lasting only 4-5 cycles can cause a wide range of sensitive customer equipment to drop out. To industrial customers, voltage sag and a momentary interruption are equivalent if both shut their process down. A typical example of voltage sag is shown in fig 1. The susceptibility of utilization equipment to voltage sag is dependent upon duration and magnitude of voltage sags and can be define.

Characteristics of Voltage Sags:Voltage sags which can cause event impacts are caused by faults on the power system. Motor starting also results in voltage sags but the magnitudes are usually not severe enough to cause equipment mis operation

How a fault results in voltage sag at a customer facility? The one line diagram given below in fig. 3 can be used to explain this phenomenon.

Consider a customer on the feeder controlled by breaker 1. In the case of a fault on this feeder, the customer will experience voltage sag during the fault and an interruption when the breaker opens to clear the fault. For temporary fault, enclosure may be successful. Anyway, sensitive equipment will almost surely trip during this interruption. Another kind of likely event would be a fault on one of the feeders from the substation or a fault somewhere on the transmission system, In either of these cases, the customer will experience a voltage sag during the actual period of fault. As soon as breakers open to clear the fault, normal voltage will be restarted at the customer's end. Fig 4 is a plot of rms voltage versus time and the waveform characteristics at the customer's location for one of these fault conditions. This waveform is typical of the customer voltage during a fault on a parallel feeder circuit that is cleared quickly by the substation breaker. The total duration of fault is 150m sec. The voltage during a fault on a parallel feeder will depend on the distance from the substation to fault point. A fault close to substation will result in much more significant sag than a fault near the end of feeder. Fig 5 shows the voltage sag magnitude at the plant bus as a function of fault location for an example system.

A single line to ground fault condition results in a much less severe voltage sag than 3-phase fault Condition due to a delta--star transformer connection at the plant. Transmission related voltage sags are normally much more consistent than those related to distribution. Because of large amounts of energy associated with transmission faults, they are cleared as soon as possible. This normally corresponds to 3-6 cycles, which is the total time for fault detection and breaker operation Normally customers do not experience an interruption for transmission fault. Transmission systems are looped or networked, as distinct from radial distribution systems. If a fault occurs as shown on the 115KV system, the protective relaying will sense the fault and breakers A and B will open to clear the fault. While the fault is on the transmission system, the entire power system, including the distribution system will experience Voltage sag. Fig 6 shown the magnitude of measured voltage sags at an industrial plant supplied from a 115 kV system. Most of the voltages were 10-30% below nominal voltage, and no momentary interrupts were measured at the plant during the monitoring period (about a year). Fig7 given a three-dimensional plot illustrating the number of sags experienced as a function of both the voltage sag magnitude and the duration.

This is a convenient way to completely characterize the actual or expected voltage sag conditions at a site. Evaluating the impact of voltage sags at a customer plant involves estimating the member of voltage sags that can be expected as a function of the voltage sag magnitude and then comparing this with equipment sensitivity. The estimate of voltage sag performance are developed by performing short-circuit simulations to determine the plant voltage as a function of fault location throughout the power system. Total circuit miles of line exposure that can affect the plant (area of vulnerability) are determined for a particular sag level. Historical fault performance (fault per year per 100 miles) can, then be used to estimate the number of sags per year that can be expected below the magnitude. A chart such as the one in fig 8. Can be drawn in splitting the expected number of voltage sags by magnitude. This information can be used directly by the customers to determine the need for power conditioning equipment at sensitive loads in the plant.

Voltage-Sag Analysis- Methodology The methodology is outlined in chapter9 (proposed) of IEEE Gold book (IEEE standard 493, recommended practice for the design of reliable industrial and commercial power system) the methodology basically consists of the following four steps:

Load Flow: A load flow representing the existing or modified system is required with an accurate zero- sequence representation. The machine reactance Xd" or Xd ' is also required. The reactance used is dependent upon the post fault time frame of interest. The machine and zero-sequence reactance are not required to calculate the voltage sag magnitude.

Voltage Sag Calculation:Sliding faults which include line-line, line to ground, line to line- to ground and three phase are applied to all the lines in the load flow. Each line is divided into equal sections and each section is faulted as shown in fig 9.

Voltage Sag Occurrence Calculation:Based upon the utilities reliability data (the number of times each line section will experience a fault) and the results of load flow and voltage sag calculations, the number of voltage sags at the customer site due to remote faults can be calculated. Depending upon the equipment connection, the voltage sag occurrence rate may be calculated in terms of either phase or line voltages dependent upon the load connection. For some facilities, both line and phase voltages may be required. The data thus obtained from load flow, Voltage sag calculation, and voltage sag occurrence calculation can be sorted and tabulated by sag magnitude, fault type, location of fault and nominal system voltage at the fault location

Study of Results of Sag- Analysis:The results can be tabulated and displayed in many different ways to recognize difficult aspects. Area of vulnerability can be plotted on a geographical map or one - line diagram (fig 9). These plots can be used to target transmission and distribution lines for enhancements in reliability. Further bar charts, and pie-charts showing the total number of voltage sags with reference to voltage level at fault point, area/zone of fault, or the fault type can be developed to help utilities focus on their system improvements (figs. 10 and 11) To examining the existing system, system modifications aimed at mitigating or reducing voltage sags can also be identified, thus enabling cost benefits analysis. Possible such system structural changes that can be identified include. Reconnection of a customer from one voltage level to another, Installation of Ferro-resonant transformers or time delayed under voltage, drop out relay to facilitate easy ride - through the sag Application of static transfer switch and energy storage system., Application of fast acting synchronous condensers, Neighborhood generation capacity addition , Increase service voltage addition through transformer tap changing, By enhancement of system reliability

Equipment Sensitivity Studies:Process controllers can be very sensitive to voltage sags. An electronic component manufacturer was experiencing problems with large chiller motors tripping off-line during voltage sag conditions. A 15VA process controller which regulates water temperature was thought to be causing individual chillers to trip. This controller was tested using a voltage sag simulator for voltage sags from 0.5-1000 cycles in duration. The controller was found to be very sensitive to voltage sags tripping at around 80% of voltage regardless of duration.

B Chip Testers: Electronic chip testers are very sensitive to voltage variations, and because of the complexity involved, often require 30 minutes or more to restart. In addition, the chips involved in the testing process can be damaged and several days' later internal electronic circuit boards in the testers may fail. A chip tester consists of a collection of electronic loads, printers, computers, monitors etc. If any one component of the total package goes down, the entire testing process is disrupted. The chip testers can be 50KVA or larger in size.

C.DC Drives: DC drives are used in many industrial processes, including printing presses and plastics manufacturing. The plastic extrusion process is one of the common applications where voltage sag can be particularly important. The extruders melt and grind plastic pellets into liquid plastic. The liquid plastic may then be blowup into a bag or processed in some other way before winder winds the plastic into spools. During voltage sag, the controls to the D.C. Drives and winders may trip. These operations are typically completely automated and an interruption can cause very expensive cleanup and restarting requirements. Losses may be of the order of Rs. 15 lakhs / event and a plant fed from a distribution system is likely to experience at least one event per month. Extra ders begin to have problems when the voltage sags to only 88% of normal, which indicates a very high level of sensitivity. Faults May miles away from the plant will cause voltage sags down to 88% level. Even protecting only the winders and controls does not serve the purpose always. When they are protected and voltage sag occurs, the controls and winders continue to work properly. However, the dc drives slow down. For severe voltage dips, the slowing down are so much that the process is interrupted. Therefore D.C. drives also need to be helped to ride through all voltage sags.

D .Programmable Logic Controllers. Their overall sensitivity to voltage sags varies greatly by portions of an overall PLC system have been found to be very sensitive The remote I/O units have been found to trip for voltages as high as 90% for a few cycles.

E. Machine Tools: Robots or complicated machines used in cutting, drilling and metal processing can be very sensitive to voltage variation. Any variation in voltage can affect the quality of the part that is being machined. Robots generally need very constant voltage to operate properly and safely. Any voltage fluctuations especially sag. May cause unsafe operation of robot. Therefore these types of machines re often set to trip at voltage levels of only 90%

Solutions to Voltage Sag Problems: Efforts by utilities and customers can reduce the number and severity of sags. A. Utility solutions: Utilities can take two main steps to reduce the detrimental effects of sags (1) Prevent fault (2) Improve fault clearing methodsFault prevention methods include activities like tree trimming, adding line arrests, washing insulators and installing animal guards. Improved fault clearing practices include activities like adding line recloses, eliminating fast tripping, adding loop schemes and modifying feeder design. These may reduce the number and /or duration of momentary interruptions and voltage sags but faults cannot be eliminated completely.B. Customer solutions: Power conditioning is the general concept behind these methods. Fig 12 is a schematic f the general approach used.Power conditioning helps to1. Isolate equipment from high frequency noise and transients.2. Provide voltage sag ride through capability

The following are some of the solutions available to provide ride - through capability to critical loads.Motor generator sets (M-G sets)Uninterruptible Power supply (UPS's)Ferro resonant, constant voltage transformers (CVT's)Magnetic synthesizersSuper conducting storage devices (SSD's)

MG sets usually utilize flying wheels for energy storage. They completely decouple the loads from electric power system Relational energy in the flywheel provides voltage regulation and voltage support during under voltage conditions. MG sets have relatively high efficiency and low initial cost. UPS's (Fig.13): Utilize batteries to store energy which is converted to usable form during an outage or voltage sag UPS technology is well established and there are many UPS configurations to choose From.

CTS can be used to enhance voltage sag ride through capability. CVT's are basically 1; transformers which are excited high on their saturation curves, thereby supplying output voltage which is fairly independent of input voltage variations. Magnetic synthesizers are generally used for larger loads. A load of at least several KVA is needed to make these units cost effective. They are often used to protect large computers and other sensitive electronic equipment, This is an electromagnetic device which generates a clean three phase ac output way form regardless of input power quality (Fig . 14) SSD's utilize a super conducting magnet (Fig.15) store energy in the same way a UPS uses batteries to store energy. SSDs occupied less space and use fewer electrical connections as compared to UPS's thus promising better reliability. They are also expected to become economically competitive.

Economic EvaluationIf the less-expensive solutions mentioned in this brief are not effective, the next step is to evaluate the life-cycle costs and effectiveness of voltage sag mitigation technologies. This task can be very challenging and tends to be beyond the expertise of most industrial facility managers. This type of evaluation requires an analysis of the costs of your voltage sag problems in terms of downtime and lost production, the costs of the devices, and an Understanding of how the mitigation devices work, including partial solutions. A good place to start in performing this type of analysis is to ask your utility or a power quality consultant for assistance. Many utilities offer power quality mitigation services or can refer you to outside specialists.

VOLTAGE SWELLSWELLA swell is the reverse form of Sag, having an increase in AC Voltage for duration of 0.5 cycles to 1 minute's time. For swells, high-impedance neutral connections, sudden large load reductions, and a single-phase fault on a three phase system are common sources. Swells can cause data errors, light flickering, electrical contact degradation, and semiconductor damage in electronics causing hard server failures. Our power conditioners and UPS Solutions are common solutions for swells. It is important to note that, much like sags, swells may not be apparent until results are seen. Having your power quality devices monitoring and logging your incoming power will help measure these events.Over-voltageOver-voltages can be the result of long-term problems that create swells. Think of an overvoltage as an extended swell. Over-voltages are also common in areas where supply transformer tap settings are set incorrectly and loads have been reduced. Over-voltage conditions can create high current draw and cause unnecessary tripping of downstream circuit breakers, as well as overheating and putting stress on equipment. Since an overvoltage is a constant swell, the same UPS and Power Conditioners will work for these. Please note however that if the incoming power is constantly in an overvoltage condition, the utility power to your facility may need correction as well. The same symptoms apply to the over-voltages and swells however since the overvoltage is more constant you should expect some excess heat. This excess heat, especially in data center environments, must be monitored.If you are experiencing any of these power quality problems we have solutions ranging from Power Conditioners / Voltage Regulators to traditional UPS Systems and Flywheel UPS Solutions. Do not hesitate to call on us.

SWELL CAUSESAs discussed previously, swells are less common than voltage sags, but also usually associated with system fault conditions. A swell can occur due to a single line-to ground fault on the system, which can also result in a temporary voltage rise on the unfaulted phases. This is especially true in ungrounded or floating ground delta systems, where the sudden change in ground reference result in a voltage rise on the ungrounded phases. On an ungrounded system, the line-to ground voltages on the ungrounded phases will be 1.73 pu during a fault condition. Close to the substation on a grounded system, there will be no voltage rise on unfaulted phases because the substation transformer is usually connected delta-wye, providing a low impedance path for the fault current. Swells can also be generated by sudden load decreases. The abrupt interruption of current can generate a large voltage, per the formula: v = L di/dt, where L is the inductance of the line, and di/dt is the change in current flow. Switching on a large capacitor bank can also cause a swell, though it more often causes an oscillatory transient.

MONITORING & TESTINGAs with other technology-driven products, the power quality monitoring products have rapidly evolved in the last fifteen years. Increased complexity and performance of VLSI components, particularly microprocessor, digital signal processors, programmable logic, and analog/digital converters, have allowed the manufacturer's of power quality monitoring instruments to include more performance in the same size package for the same or reduced price. Different types of monitoring equipment is available, depending on the user's knowledge base and requirements. The four basic categories of power quality monitors (also known as power line disturbance monitors) are: event indicators, text monitors, solid state recording volt/ammeters, and graphical monitors. While all of these devices can be used to measure/monitor sags and swells, the effectiveness of each depends on what information the user wants to gain. Since sags and swells are relatively slow events (as opposed to microsecond duration transients), the wide variety of instruments are generally capable of capturing a sag or swell with reasonable reliability. Event indicators are usually on the lower price end of the market. They indicate to the user that a sag or swell has occurred through visual means, such as indicator lights or illuminated bar graphs. Some products will store the worst case amplitudes of such and/or the number of occurrences of the type of event. Most such device do not provide an indication of the time of occurrence or the duration. The voltage limit detectors may be preset or programmable, with the accuracy being in the 2-5% range. Textual-based monitors were actually the first dedicated power quality monitors, produced back in 1976. The function of these instruments is similar to the event indicators, except the output is in alphanumeric format Additional information, such as duration and time-of-occupance is often included. Some of these products allow for the correlation of other information (such as environmental parameters and system status levels) to assist the user in determining the cause of the event. Solid state recording volt/ammeters have replaced the older pen-and-ink chart recorders as a means of providing a graphical history of an event. These devices typically lack the resolution necessary for monitoring fault-clearing sags. Sampling techniques range from average of several cycles to samples over 2-30 cycles. The averaging over several cycles may mask the sag or swell, as well as result in misleading amplitudes. Sampling over multiple cycles will not properly represent the event either. Graphical monitors provide the most information about sag or swell. Most graphical monitors provide a cycle-by-cycle picture of the disturbance, as well as recording minimum/maximum values, duration, and time-of-occurrence. The three-phase voltage graphs, coupled with graphs of neutral to ground voltage, phase currents, neutral current (in wye), and ground currents, will usually provide the user with enough information to determine if the fault occurred upstream or downstream. The timing and magnitude information can often identify the source of the fault. For example, if the phase current levels of the load did not change prior to the voltage sag; the fault is more likely upstream. If the magnitude of the sag is down to 20% of nominal, it is likely that the fault was close by. If the sag duration was less than four cycles, it was most likely a transmission system fault. If the swell waveform is preceded by a oscillatory transient, it may be the result of a power factor correction capacitor being switched on. Line-to-neutral voltage sag is often accompanied by a neutral-to-ground voltage swell. The location of the monitor, power supply wiring, measurement input wiring, and immunization from RFI/EMI is especially critical with the higher performance graphical monitors. The monitor itself must also be capable of riding through the sag and surviving extended duration swells. The functionality of the monitor should be thoroughly evaluated in the laboratory, under simulated disturbances, before placing out in the field. Just because it didn't record it, does not mean it didn't happen. Unless there is significant information pointing to the cause of the disturbance before the monitoring begins, it is common practice to begin at the point of common coupling with the utility service as the initial monitoring point. If the initial monitoring period indicates that the fault occurred on the utility side of the service transformer, then further monitoring would not be necessary until attempting to determine the effectiveness of the solution. If the source of the disturbance is determined to be internal to the facility, the placing multiple monitors on the various feeds within the facility would most likely produce the optimal answer in the shortest time period. Otherwise, the monitor must be moved from circuit to circuit, with particular attention to circuits powering suspected sources, and the circuits of the susceptible devices. Recent developments in artificial intelligence tools, especially fuzzy logic, have allow software vendors to develop products that allow knowledge and reasoning patterns to be stored in the software program. Further analysis of the event, beyond the IEEE 1159 classifications, is possible. These include the severity of the event, relative to the type of equipment that would be effected, and probability factors on the cause of the disturbance. Multiple, successive sags that return to nominal for an adequate time for the power supply capacitors to recharge may not be as severe as a longer duration sag of a higher amplitude.

SOLUTIONSThe first step in reducing the severity of the system sags is to reduce the number of faults. From the utility side, transmission-line shielding can prevent lighting induced faults. If tower-footing resistance is high, the surge energy from a lightning stroke is not absorbed quickly into the ground. Since high tower-footing resistance is an import factor in causing back flash from static wire to phase wire, steps to reduce such should be taken. The probability of flashover can be reduced by applying surge arresters to divert current to ground. Tree-trimming programs around distribution lines is becoming more difficult to maintain, with the continual reductions in personnel and financial constraints in the utility companies. While the use of underground lines reduces the weather-related causes, there are additional problems from equipment failures in the underground environment and construction accidents. The solutions within the facility are varied, depending on the financial risk at stake, the susceptibility levels and the power requirements of the effected device. Depending on the transformer configuration, it may be possible to mitigate the problem with a transformer change. "It is virtually impossible for an SLTG condition on the utility system to cause a voltage sag below 30% at the customer bus, when the customer is supplied through a delta-wye or wye-delta transformer."

For wye-wye and delta-delta connections two phase-to-phase voltages will drop to 58% of nominal, while the other phase-to-phase is unaffected. However, for delta-wye and wye-delta connections, one phase-to-phase voltage will be as low as 33% of nominal, while the other two voltages will be 88% of nominal. It is the circulating fault current in the delta secondary windings that results in a voltage on each winding. Another possible solution is through the procurement specification. If a pre-installation site survey is done, the distribution curve and probability of the sags and/or swells can be determined. The user then specifies such information in the equipment procurement specifications. Only equipment with acceptable ride through characteristics would then be used. When neither of the above solutions are practical or adequate, some form of additional voltage regulator are required to maintain constant output voltage to the effected device, despite the variation in input voltage. Each type has its own disadvantage and advantages for a given application. The utility companies can add dynamic voltage restorers, static condensers, fault current limiters, and/or high-energy surge arresters. Since these are beyond the control of the end user of the electricity, the following concentrates on "in-the-facility" solution. These include: Ferro resonant transformers, magnetically controlled voltage regulators (3-10 cycle response); electronic tap switching transformers (1-3 cycles); shielded isolation transformers; static transfer switches (within 4 milliseconds); static UPSs; and, rotary UPSs.

FERRORESONANT TRANSFORMERSFerro resonant transformers, also called constant-voltage transformers (CVT), can handle most voltage sags. Ferro resonant transformers can have separate input and output windings, which can provide voltage transformation and common-mode noise isolation as well as voltage regulation. While CVTs provide excellent regulation, they have limited overload capacity and poor efficiency at low loads. At a load of 25% of rating, they require an input of a minimum of 30% of nominal to maintain a +3/-6% output. At 50% load of rating, they typically require 46% of nominal input for regulation, which goes to 71% of nominal input at full load. Therefore, for maximum improvement of voltage sag ride through capability, CVT should be sized about four times greater than the load. Ferro resonant CVTs are most effective for constant, low power loads, such as personal computers or process controllers. Variable loads present problems because of the tuned circuit on the transformer output. Ferro resonant transformers have a nonlinear response, similar to that of a regular transformer when excited high on its saturation Curve.MAGNETICALLY CONTROLLED VOLTAGE REGULATORSMagnetic synthesizers use transformers, inductors and capacitors to synthesize 3- phase voltage outputs. Enough energy is stored in the capacitors to ride through one cycle. They use special autotransformers, with buck-boost windings to control the voltage. The effect of the buck-boost windings is varied by a control winding with DC current that affects the saturation of the core. The control-winding current is produced by electronic sensing and control circuits. The response time is relatively slow (3-10 cycles).TAP SWITCHING TRANSFORMERSElectronic tap-switching transformers have the high efficient, low impedance, noise isolation, and overload capacity of a transformer. These regulators use solid state switches (thyristors) to change the turns ratio on a tapped coil winding. The switching is controlled by electronic sensing circuits, and can react relatively quickly (1-3 cycles). Thyristor switching at zero voltage is easier and less costly than at zero current, but can cause transient voltages in the system, as the current and voltage are only in phase at unity power factor. Thus, switching at zero-current is preferred. The voltage change is in discrete steps, but the steps can be small enough so as not to induce additional problems.

STATIC UPSA UPS can provide complete isolation from all power line disturbances, in addition to providing ride-through during an outage. A static UPS consist of a rectifier AC to DC converter, DC bus with a floating battery, DC to AC inverter, and solid state bypass switch. The rectifier converts the raw input power to DC, which keeps the floating battery fully charged and supplies power to the inverter section. The inverters generate 6 or 12 step waves, pulse-width modulated waves, or a combination of the two, to create a synthetic sine-wave output. Inverter output should be a stable, low-distortion sine wave, provided there is adequate filtering in the output stage. The batteries supply the DC bus voltage when the AC voltage is reduced. There units range from a few hundred VA to 750kVA or higher. Since they are constantly running, there is no switch-over time, except when the bypass switch is activities. The capacity of the battery banks determines the length of ride-through.

ROTARY UPS/MOTOR GENERATORSMotor generator sets can also provide power conditioning by fully isolating the output power of the generator from disturbances of the input power (except for sustained outages). Various configurations are possible, including single shaft synchronous MG, DC motor driven MG, 3600 rpm induction motor with a flywheel driving a 1800 rpm generator, synchronous MG with an additional DC machine on same shaft, which powers AC generator with AC fails; or, variable speed, constant frequency synchronous MG (varies number of poles so that frequency remains the same. The inertia of an MG set, (especially if supplemented by a flywheel), can ride-through several seconds of input power interruption. Since the generator output can be of different voltage and frequency from the motor input, conversion from 60 Hz to 400 Hz is possible.

NEWER SOLUTIONSEPRI has been working with PSEG and Westinghouse Electric Corp to develop an active power line conditioner, which will combine active harmonic filtering, line voltage regulation and transient voltage surge protection in a single compact unit. To date, 5KVA, 50KVA and 150KVA units are available. Several successfully applications of superconductivity magnetic-storage systems have been carried out in the United States. The stored energy that is provided by the batteries in a static UPS, or the inertia of the motor in a MG set, is instead provided by current stored in a superconductive magnetic system. This energy can be quickly coupled back into the system, when the AC input power is inadequate.

FLEXIBLE AC TRANSMISSION SYSTEMS (FACTS)

Flexible AC Transmission Systems, called FACTS, got in the recent years a well known term for higher controllability in power systems by means of power electronic devices. Several FACTS-devices have been introduced for various applications worldwide. A number of new types of devices are in the stage of being introduced in practice.

In most of the applications the controllability is used to avoid cost intensive or landscape requiring extensions of power systems, for instance like upgrades or additions of substations and power lines. FACTS-devices provide a better adaptation to varying operational conditions and improve the usage of existing installations. The basic applications of FACTS-devices are:

Power flow control, Increase of transmission capability, Voltage control, Reactive power compensation, Stability improvement, Power quality improvement, Power conditioning, Flicker mitigation, Interconnection of renewable and distributed generation and storages.

Figure shows the basic idea of FACTS for transmission systems. The usage of lines for active power transmission should be ideally up to the thermal limits. Voltage and stability limits shall be shifted with the means of the several different FACTS devices. It can be seen that with growing line length, the opportunity for FACTS devices gets more and more important.

The influence of FACTS-devices is achieved through switched or controlled shunt compensation, series compensation or phase shift control. The devices work electrically as fast current, voltage or impedance controllers. The power electronic allows very short reaction times down to far below one second.

The development of FACTS-devices has started with the growing capabilities of power electronic components. Devices for high power levels have been made available in converters for high and even highest voltage levels. The overall starting points are network elements influencing the reactive power or the impedance of a part of the power system. Figure 1.2 shows a number of basic devices separated into the conventional ones and the FACTS-devices.

For the FACTS side the taxonomy in terms of 'dynamic' and 'static' needs some explanation. The term 'dynamic' is used to express the fast controllability of FACTS-devices provided by the power electronics. This is one of the main differentiation factors from the conventional devices. The term 'static' means that the devices have no moving parts like mechanical switches to perform the dynamic controllability. Therefore most of the FACTS-devices can equally be static and dynamic.

The left column in Figure 1.2 contains the conventional devices build out of fixed or mechanically switch able components like resistance, inductance or capacitance together with transformers. The FACTS-devices contain these elements as well but use additional power electronic valves or converters to switch the elements in smaller steps or with switching patterns within a cycle of the alternating current. The left column of FACTS-devices uses Thyristor valves or converters. These valves or converters are well known since several years. They have low losses because of their low switching frequency of once a cycle in the converters or the usage of the Thyristors to simply bridge impedances in the valves.

The right column of FACTS-devices contains more advanced technology of voltage source converters based today mainly on Insulated Gate Bipolar Transistors (IGBT) or Insulated Gate Commutated Thyristors (IGCT). Voltage Source Converters provide a free controllable voltage in magnitude and phase due to a pulse width modulation of the IGBTs or IGCTs. High modulation frequencies allow to get low harmonics in the output signal and even to compensate disturbances coming from the network. The disadvantage is that with an increasing switching frequency, the losses are increasing as well. Therefore special designs of the converters are required to compensate this.

Configurations of FACTS-Devices:

Shunt Devices:

The most used FACTS-device is the SVC or the version with Voltage Source Converter called STATCOM. These shunt devices are operating as reactive power compensators. The main applications in transmission, distribution and industrial networks are:

Reduction of unwanted reactive power flows and therefore reduced network losses. Keeping of contractual power exchanges with balanced reactive power. Compensation of consumers and improvement of power quality especially with huge demand fluctuations like industrial machines, metal melting plants, railway or underground train systems. Compensation of Thyristor converters e.g. in conventional HVDC lines. Improvement of static or transient stability.

Almost half of the SVC and more than half of the STATCOMs are used for industrial applications. Industry as well as commercial and domestic groups of users require power quality. Flickering lamps are no longer accepted, nor are interruptions of industrial processes due to insufficient power quality. Railway or underground systems with huge load variations require SVCs or STATCOMs.

SVC:Electrical loads both generate and absorb reactive power. Since the transmitted load varies considerably from one hour to another, the reactive power balance in a grid varies as well. The result can be unacceptable voltage amplitude variations or even a voltage depression, at the extreme a voltage collapse.

A rapidly operating Static Var Compensator (SVC) can continuously provide the reactive power required to control dynamic voltage oscillations under various system conditions and thereby improve the power system transmission and distribution stability.

Applications of the SVC systems in transmission systems:a. To increase active power transfer capacity and transient stability marginb. To damp power oscillationsc. To achieve effective voltage control

In addition, SVCs are also used

1. in transmission systemsa. To reduce temporary over voltagesb. To damp sub synchronous resonancesc. To damp power oscillations in interconnected power systems

2. in traction systemsa. To balance loadsb. To improve power factorc. To improve voltage regulation

3. In HVDC systemsa. To provide reactive power to acdc converters

4. In arc furnacesa. To reduce voltage variations and associated light flicker

Installing an SVC at one or more suitable points in the network can increase transfer capability and reduce losses while maintaining a smooth voltage profile under different network conditions. In addition an SVC can mitigate active power oscillations through voltage amplitude modulation.SVC installations consist of a number of building blocks. The most important is the Thyristor valve, i.e. stack assemblies of series connected anti-parallel Thyristors to provide controllability. Air core reactors and high voltage AC capacitors are the reactive power elements used together with the Thyristor valves. The step up connection of this equipment to the transmission voltage is achieved through a power transformer.

SVC building blocks and voltage / current characteristic

In principle the SVC consists of Thyristor Switched Capacitors (TSC) and Thyristor Switched or Controlled Reactors (TSR / TCR). The coordinated control of a combination of these branches varies the reactive power as shown in Figure. The first commercial SVC was installed in 1972 for an electric arc furnace. On transmission level the first SVC was used in 1979. Since then it is widely used and the most accepted FACTS-device.

SVCSVC USING A TCR AND AN FC:In this arrangement, two or more FC (fixed capacitor) banks are connected to a TCR (thyristor controlled reactor) through a step-down transformer. The rating of the reactor is chosen larger than the rating of the capacitor by an amount to provide the maximum lagging vars that have to be absorbed from the system. By changing the firing angle of the thyristor controlling the reactor from 90 to 180, the reactive power can be varied over the entire range from maximum lagging vars to leading vars that can be absorbed from the system by this compensator.

SVC of the FC/TCR type:

The main disadvantage of this configuration is the significant harmonics that will be generated because of the partial conduction of the large reactor under normal sinusoidal steady-state operating condition when the SVC is absorbing zero MVAr. These harmonics are filtered in the following manner. Triplex harmonics are canceled by arranging the TCR and the secondary windings of the step-down transformer in delta connection. The capacitor banks with the help of series reactors are tuned to filter fifth, seventh, and other higher-order harmonics as a high-pass filter. Further losses are high due to the circulating current between the reactor and capacitor banks.

Comparison of the loss characteristics of TSCTCR, TCRFC compensators and synchronous condenser

These SVCs do not have a short-time overload capability because the reactors are usually of the air-core type. In applications requiring overload capability, TCR must be designed for short-time overloading, or separate thyristor-switched overload reactors must be employed.

SVC USING A TCR AND TSC:

This compensator overcomes two major shortcomings of the earlier compensators by reducing losses under operating conditions and better performance under large system disturbances. In view of the smaller rating of each capacitor bank, the rating of the reactor bank will be 1/n times the maximum output of the SVC, thus reducing the harmonics generated by the reactor. In those situations where harmonics have to be reduced further, a small amount of FCs tuned as filters may be connected in parallel with the TCR.

SVC of combined TSC and TCR type

When large disturbances occur in a power system due to load rejection, there is a possibility for large voltage transients because of oscillatory interaction between system and the SVC capacitor bank or the parallel. The LC circuit of the SVC in the FC compensator. In the TSCTCR scheme, due to the flexibility of rapid switching of capacitor banks without appreciable disturbance to the power system, oscillations can be avoided, and hence the transients in the system can also be avoided. The capital cost of this SVC is higher than that of the earlier one due to the increased number of capacitor switches and increased control complexity.

STATCOM:

In 1999 the first SVC with Voltage Source Converter called STATCOM (STATic COMpensator) went into operation. The STATCOM has a characteristic similar to the synchronous condenser, but as an electronic device it has no inertia and is superior to the synchronous condenser in several ways, such as better dynamics, a lower investment cost and lower operating and maintenance costs. A STATCOM is build with Thyristors with turn-off capability like GTO or today IGCT or with more and more IGBTs. The static line between the current limitations has a certain steepness determining the control characteristic for the voltage.

The advantage of a STATCOM is that the reactive power provision is independent from the actual voltage on the connection point. This can be seen in the diagram for the maximum currents being independent of the voltage in comparison to the SVC. This means, that even during most severe contingencies, the STATCOM keeps its full capability.

In the distributed energy sector the usage of Voltage Source Converters for grid interconnection is common practice today. The next step in STATCOM development is the combination with energy storages on the DC-side. The performance for power quality and balanced network operation can be improved much more with the combination of active and reactive power.

STATCOM structure and voltage / current characteristic

STATCOMs are based on Voltage Sourced Converter (VSC) topology and utilize either Gate-Turn-off Thyristors (GTO) or Isolated Gate Bipolar Transistors (IGBT) devices. The STATCOM is a very fast acting, electronic equivalent of a synchronous condenser. If the STATCOM voltage, Vs, (which is proportional to the dc bus voltage Vc) is larger than bus voltage, Es, then leading or capacitive VARS are produced. If Vs is smaller then Es then lagging or inductive VARS are produced.

6 Pulses STATCOM

The three phases STATCOM makes use of the fact that on a three phase, fundamental frequency, steady state basis, and the instantaneous power entering a purely reactive device must be zero. The reactive power in each phase is supplied by circulating the instantaneous real power between the phases. This is achieved by firing the GTO/diode switches in a manner that maintains the phase difference between the ac bus voltage ES and the STATCOM generated voltage VS. Ideally it is possible to construct a device based on circulating instantaneous power which has no energy storage device (ie no dc capacitor).

A practical STATCOM requires some amount of energy storage to accommodate harmonic power and ac system unbalances, when the instantaneous real power is non-zero. The maximum energy storage required for the STATCOM is much less than for a TCR/TSC type of SVC compensator of comparable rating.

STATCOM Equivalent Circuit

Several different control techniques can be used for the firing control of the STATCOM. Fundamental switching of the GTO/diode once per cycle can be used. This approach will minimize switching losses, but will generally utilize more complex transformer topologies. As an alternative, Pulse Width Modulated (PWM) techniques, which turn on and off the GTO or IGBT switch more than once per cycle, can be used. This approach allows for simpler transformer topologies at the expense of higher switching losses.

The 6 Pulse STATCOM using fundamental switching will of course produce the 6 N1 harmonics. There are a variety of methods to decrease the harmonics. These methods include the basic 12 pulse configuration with parallel star / delta transformer connections, a complete elimination of 5th and 7th harmonic current using series connection of star/star and star/delta transformers and a quasi 12 pulse method with a single star-star transformer, and two secondary windings, using control of firing angle to produce a 30phase shift between the two 6 pulse bridges. This method can be extended to produce a 24 pulse and a 48 pulse STATCOM, thus eliminating harmonics even further. Another possible approach for harmonic cancellation is a multi-level configuration which allows for more than one switching element per level and therefore more than one switching in each bridge arm. The ac voltage derived has a staircase effect, dependent on the number of levels. This staircase voltage can be controlled to eliminate harmonics.

Series Devices:

Series devices have been further developed from fixed or mechanically switched compensations to the Thyristor Controlled Series Compensation (TCSC) or even Voltage Source Converter based devices.

The main applications are: Reduction of series voltage decline in magnitude and angle over a power line, Reduction of voltage fluctuations within defined limits during changing power transmissions, Improvement of system damping resp. damping of oscillations, Limitation of short circuit currents in networks or substations, Avoidance of loop flows resp. power flow adjustments.

TCSC:

Thyristor Controlled Series Capacitors (TCSC) address specific dynamical problems in transmission systems. Firstly it increases damping when large electrical systems are interconnected. Secondly it can overcome the problem of Sub Synchronous Resonance (SSR), a phenomenon that involves an interaction between large thermal generating units and series compensated transmission systems.

The TCSC's high speed switching capability provides a mechanism for controlling line power flow, which permits increased loading of existing transmission lines, and allows for rapid readjustment of line power flow in response to various contingencies. The TCSC also can regulate steady-state power flow within its rating limits.

From a principal technology point of view, the TCSC resembles the conventional series capacitor. All the power equipment is located on an isolated steel platform, including the Thyristor valve that is used to control the behavior of the main capacitor bank. Likewise the control and protection is located on ground potential together with other auxiliary systems. Figure shows the principle setup of a TCSC and its operational diagram. The firing angle and the thermal limits of the Thyristors determine the boundaries of the operational diagram.

Advantages Continuous control of desired compensation level Direct smooth control of power flow within the network Improved capacitor bank protection Local mitigation of sub synchronous resonance (SSR). This permits higher levels of compensation in networks where interactions with turbine-generator torsional vibrations or with other control or measuring systems are of concern. Damping of electromechanical (0.5-2 Hz) power oscillations which often arise between areas in a large interconnected power network. These oscillations are due to the dynamics of inter area power transfer and often exhibit poor damping when the aggregate power tranfer over a corridor is high relative to the transmission strength.

Shunt And Series Devices

Dynamic Power Flow Controller

A new device in the area of power flow control is the Dynamic Power Flow Controller (DFC). The DFC is a hybrid device between a Phase Shifting Transformer (PST) and switched series compensation.

A functional single line diagram of the Dynamic Flow Controller is shown in Figure 1.19. The Dynamic Flow Controller consists of the following components:

a standard phase shifting transformer with tap-changer (PST) series-connected Thyristor Switched Capacitors and Reactors (TSC / TSR) A mechanically switched shunt capacitor (MSC). (This is optional depending on the system reactive power requirements)

Based on the system requirements, a DFC might consist of a number of series TSC or TSR. The mechanically switched shunt capacitor (MSC) will provide voltage support in case of overload and other conditions. Normally the reactance of reactors and the capacitors are selected based on a binary basis to result in a desired stepped reactance variation. If a higher power flow resolution is needed, a reactance equivalent to the half of the smallest one can be added.

The switching of series reactors occurs at zero current to avoid any harmonics. However, in general, the principle of phase-angle control used in TCSC can be applied for a continuous control as well. The operation of a DFC is based on the following rules:

TSC / TSR are switched when a fast response is required. The relieve of overload and work in stressed situations is handled by the TSC / TSR. The switching of the PST tap-changer should be minimized particularly for the currents higher than normal loading. The total reactive power consumption of the device can be optimized by the operation of the MSC, tap changer and the switched capacities and reactors.

In order to visualize the steady state operating range of the DFC, we assume an inductance in parallel representing parallel transmission paths. The overall control objective in steady state would be to control the distribution of power flow between the branch with the DFC and the parallel path. This control is accomplished by control of the injected series voltage.

The PST (assuming a quadrature booster) will inject a voltage in quadrature with the node voltage. The controllable reactance will inject a voltage in quadrature with the throughput current. Assuming that the power flow has a load factor close to one, the two parts of the series voltage will be close to collinear. However, in terms of speed of control, influence on reactive power balance and effectiveness at high/low loading the two parts of the series voltage has quite different characteristics. The steady state control range for loadings up to rated current is illustrated in Figure 1.20, where the x-axis corresponds to the throughput current and the y-axis corresponds to the injected series voltage.

Fig. Operational diagram of a DFC

Operation in the first and third quadrants corresponds to reduction of power through the DFC, whereas operation in the second and fourth quadrants corresponds to increasing the power flow through the DFC. The slope of the line passing through the origin (at which the tap is at zero and TSC / TSR are bypassed) depends on the short circuit reactance of the PST.

Starting at rated current (2 kA) the short circuit reactance by itself provides an injected voltage (approximately 20 kV in this case). If more inductance is switched in and/or the tap is increased, the series voltage increases and the current through the DFC decreases (and the flow on parallel branches increases). The operating point moves along lines parallel to the arrows in the figure. The slope of these arrows depends on the size of the parallel reactance. The maximum series voltage in the first quadrant is obtained when all inductive steps are switched in and the tap is at its maximum.

Now, assuming maximum tap and inductance, if the throughput current decreases (due e.g. to changing loading of the system) the series voltage will decrease. At zero current, it will not matter whether the TSC / TSR steps are in or out, they will not contribute to the series voltage.Consequently, the series voltage at zero current corresponds to rated PST series voltage. Next, moving into the second quadrant, the operating range will be limited by the line corresponding to maximum tap and the capacitive step being switched in (and the inductive steps by-passed). In this case, the capacitive step is approximately as large as the short circuit reactance of the PST, giving an almost constant maximum voltage in the second quadrant.

Unified Power Flow Controller:

The UPFC is a combination of a static compensator and static series compensation. It acts as a shunt compensating and a phase shifting device simultaneously.

Fig. Principle configuration of an UPFC

The UPFC consists of a shunt and a series transformer, which are connected via two voltage source converters with a common DC-capacitor. The DC-circuit allows the active power exchange between shunt and series transformer to control the phase shift of the series voltage. This setup, as shown in Figure 1.21, provides the full controllability for voltage and power flow. The series converter needs to be protected with a Thyristor bridge. Due to the high efforts for the Voltage Source Converters and the protection, an UPFC is getting quite expensive, which limits the practical applications where the voltage and power flow control is required simultaneously.

OPERATING PRINCIPLE OF UPFC

The basic components of the UPFC are two voltage source inverters (VSIs) sharing a common dc storage capacitor, and connected to the power system through coupling transformers. One VSI is connected to in shunt to the transmission system via a shunt transformer, while the other one is connected in series through a series transformer.A basic UPFC functional scheme is shown in fig.1

The series inverter is controlled to inject a symmetrical three phase voltage system (Vse), of controllable magnitude and phase angle in series with the line to control active and reactive power flows on the transmission line. So, this inverter will exchange active and reactive power with the line. The reactive power is electronically provided by the series inverter, and the active power is transmitted to the dc terminals. The shunt inverter is operated in such a way as to demand this dc terminal power (positive or negative) from the line keeping the voltage across the storage capacitor Vdc constant. So, the net real power absorbed from the line by the UPFC is equal only to the losses of the inverters and their transformers. The remaining capacity of the shunt inverter can be used to exchange reactive power with the line so to provide a voltage regulation at the connection point.The two VSIs can work independently of each other by separating the dc side. So in that case, the shunt inverter is operating as a STATCOM that generates or absorbs reactive power to regulate the voltage magnitude at the connection point. Instead, the series inverter is operating as SSSC that generates or absorbs reactive power to regulate the current flow, and hence the power low on the transmission line.The UPFC has many possible operating modes. In particular, the shunt inverter is operating in such a way to inject a controllable current, ish into the transmission line. The shunt inverter can be controlled in two different modes:VAR Control Mode: The reference input is an inductive or capacitive VAR request. The shunt inverter control translates the var reference into a corresponding shunt current request and adjusts gating of the inverter to establish the desired current. For this mode of control a feedback signal representing the dc bus voltage, Vdc, is also required.Automatic Voltage Control Mode: The shunt inverter reactive current is automatically regulated to maintain the transmission line voltage at the point of connection to a reference value. For this mode of control, voltage feedback signals are obtained from the sending end bus feeding the shunt coupling transformer.The series inverter controls the magnitude and angle of the voltage injected in series with the line to influence the power flow on the line. The actual value of the injected voltage can be obtained in several ways.Direct Voltage Injection Mode: The reference inputs are directly the magnitude and phase angle of the series voltage.Phase Angle Shifter Emulation mode: The reference input is phase displacement between the sending end voltage and the receiving end voltage. Line Impedance Emulation mode: The reference input is an impedance value to insert in series with the line impedanceAutomatic Power Flow Control Mode: The reference inputs are values of P and Q to maintain on the transmission line despite system changes.

DYNAMIC VOLTAGE RESTORERThe major objectives are to increase the capacity utilization of distribution feeders (by minimizing the rms values of the line currents for a specified power demand), reduce the losses and improve power quality at the load bus. The major assumption was to neglect the variations In the source voltages. This essentially implies that the dynamics of the source voltage is much slower than the load dynamics. When the fast variations in the source voltage cannot be ignored, these can affect the performance of critical loads such as (a) semiconductor fabrication plants (b) paper mills (c) food processing plants and (d) automotive assembly plants. The most common disturbances in the source voltages are the voltage sags or swells that can be due to (i) disturbances arising in the transmission system, (ii) adjacent feeder faults and (iii) fuse or breaker operation. Voltage sags of even 10% lasting for 5-10 cycles can result in costly damage in critical loads. The voltage sags can arise due to symmetrical or unsymmetrical faults. In the latter case, negative and zero sequence components are also present. Uncompensated nonlinear loads in the distribution system can cause harmonic components in the supply voltages. To mitigate the problems caused by poor quality of power supply, series connected compensators are used. These are called as Dynamic Voltage Restorer (DVR) in the literature as their primary application is to compensate for voltage sags and swells. Their configuration is similar to that of SSSC, discussed in chapter 7. However, the control techniques are different. Also, a DVR is expected to respond fast (less than 1/4 cycle) and thus employs PWM converters using IGBT or IGCT devices. The first DVR entered commercial service on the Duke Power System in U.S.A. in August 1996. It has a rating of 2 MVA with 660 kJ of energy storage and is capable of compensating 50% voltage sag for a period of 0.5 second (30 cycles). It was installed to protect a highly automated yarn manufacturing and rug weaving facility. Since then, several DVRs have been installed to protect microprocessor fabrication plants, paper mills etc. Typically, DVRs are made of modular design with a module rating of 2 MVA or 5 MVA. They have been installed in substations of voltage rating from 11 kV to 69 kV. A DVR has to supply energy to the load during the voltage sags. If a DVR has to supply active power over longer periods, it is convenient to provide a shunt converter that is connected to the DVR on the DC side. As a matter of fact one could envisage a combination of DSTATCOM and DVR connected on the DC side to compensate for both load and supply voltage variations. In this section, we discuss the application of DVR for fundamental frequency voltage...The voltage source converter is typically one or more converters connected in series to provide the required voltage rating. The DVR can inject a (fundamental frequency) voltage in each phase of required magnitude and phase. The DVR has two operating modes 1. Standby (also termed as short circuit operation (SCO) mode) where the voltage injected has zero magnitude.2. Boost (when the DVR injects a required voltage of appropriate magnitude and phase to restore the prefault load bus voltage). The power circuit of DVR shown in Fig. 14.1 has four components listed below.1. Voltage Source Converter (VSC)This could be a 3 phase - 3 wire VSC or 3 phase - 4 wire VSC. The latter permits the injection of zero-sequence voltages. Either a conventional two level converter (Graetz bridge) or a three level converter is used.

2. Boost or Injection TransformersThree single phase transformers are connected in series with the distribution feeder to couple the VSC (at the lower voltage level) to the higher distribution voltage level. The three single transformers can be connected with star/open star winding or delta/open star winding. The latter does not permit the injection of the zero sequence voltage. The choice of the injection transformer winding depends on the connections of the step down trans- former that feeds the load. If a Y connected transformer (as shown in Fig. 14.1) is used, there is no need to compensate the zero sequence volt- ages. However if Y Y connection with neutral grounding is used, the zero sequence voltage may have to be compensated. It is essential to avoid the saturation in the injection transformers.3. Passive FiltersThe passive filters can be placed either on the high voltage side or the converter side of the boost transformers. The advantages of the converter side filters are (a) the components are rated at lower voltage and (b) higher order harmonic currents (due to the VSC) do not own through the transformer windings. The disadvantages are that the filter inductor causes voltage drop and phase (angle) shift in the (fundamental component of) voltage injected. This can affect the control scheme of DVR. The location of the filter o the high voltage side overcomes the drawbacks (the leakage reactance of the transformer can be used as a filter inductor), but results in higher ratings of the transformers as high frequency currents can ow through the windings.4. Energy StorageThis is required to provide active power to the load during deep voltage sags. Lead-acid batteries, ywheel or SMES can be used for energy storage. It is also possible to provide the required power on the DC side of the VSC by an auxiliary bridge converter that is fed from an auxiliary AC supply.

CONTROL STRATEGY:There are three basic control strategies as follows.1. Pre-Sag CompensationThe supply voltage is continuously tracked and the load voltage is compensated to the pre-sag condition. This method results in (nearly) undisturbed load voltage, but generally requires higher rating of the DVR. Before a sag occur, VS = VL = Vo. The voltage sag results in drop in the magnitude of the supply voltage to VS1. The phase angle of the supply also may shift see Fig. 14.2). The DVR injects a voltage VC1 such that the load voltage (VL = VS1 + VC1) remains at Vo (both in magnitude and phase). It is claimed that some loads are sensitive to phase jumps and it is necessary to compensate for both the phase jumps and the voltage sags.

2. In-phase CompensationThe voltage injected by the DVR is always in phase with the supply voltage regardless of the load current and the pre-sag voltage (Vo). This control strategy results in the minimum value of the injected voltage (magnitude). However, the phase of the load voltage is disturbed. For loads which are not sensitive to the phase jumps, this control strategy results in optimum utilization of the voltage rating of the DVR. The power requirements for the DVR are not zero for these strategies3. Minimum Energy CompensationNeglecting losses, the power requirements of the DVR are zero if the injected voltage (VC) is in quadrature with the load current. To raise the voltage at the load bus, the voltage injected by the DVR is capacitive and VL leads VS1 (see Fig. 14.3). Fig. 14.3 also shows the in-phase compensation for comparison. It is to be noted that the current phasor is determined by the load bus voltage phasor and the power factor of the load.

Implementation of the minimum energy compensation requires the measurement of the load current phasor in addition to the supply voltage. When VC is in quadrature with the load current, DVR supplies only reactive power. However, full load voltage compensation is not possible Unless the supply voltage is above a minimum value that depends on the load power factor. When the magnitude of VC is not constrained, the minimum value of VS that still allows full compensation is where is the power factor angle and Vo is the required magnitude of the Load bus voltage. If the magnitude of the injected voltage is limited (V max C ), the mini- mum supply voltage that allows full compensation is given by The expressions (14.1) and (14.2) follow from the phasor diagrams shown in Fig. 14.4. Note that at the minimum source voltage, the current is in phase with VS for the case (a).CONTROL AND PROTECTIONThe control and protection of a DVR designed to compensate voltage sags must consider the following functional requirements. 1. When the supply voltage is normal, the DVR operates in a standby mode with zero voltage injection. However if the energy storage device (say batteries) is to be charged, then the DVR can operate in a self- charging control mode.2. When a voltage sag/swell occurs, the DVR needs to inject three single phase voltages in synchronism with the supply in a very short time. Each phase of the injected voltage can be controlled independently in magnitude and phase. However, zero sequence voltage can be eliminated in situations where it has no effect. The DVR draws active power from the energy source and supplies this along with the reactive power (required) to the load.3. If there is a fault on the downstream of the DVR, the converter is by- passed temporarily using thyristor switches to protect the DVR against over currents. The threshold is determined by the current ratings of the DVR.The overall design of DVR must consider the following parameters:1. Ratings of the load and power factor2. Voltage rating of the distribution line3. Maximum single phase sag (in percentage)4. Maximum three phase sag (in percentage)5. Duration of the voltage sag (in milliseconds)6. The voltage time area (this is an indication of the energy requirements)7. Recovery time for the DC link voltage to 100%8. Over current capability without going into bypass mode.Typically, a DVR may be designed to protect a sensitive load against 35% of three phase voltage sags or 50% of the single phase sag. The duration of the sag could be 200 ms. The DVR can compensate higher voltage sags lasting for shorter durations or allow longer durations (up to 500 ms) for smaller voltage sags. The response time could be as small as 1 ms.

POSICAST CONTROLINVENTED in the late 1950s, Posicast is a feedforward control method that dampens oscillations in systems whose other transient specifications are otherwise acceptable. When properly tuned, the controlled system yields a transient response that has deadbeat nature.Consider a system having a lightly damped step response as shown in Fig. 1(a). The overshoot in the response can be described by two parameters. First, the time to the first peak is one half the under damped response period Td. Second, the peak value is described by 1 +, where the normalized overshoot, which ranges from zero to one is. Zero overshoot corresponds to critical damping.

(a) A lightly damped transient response.

(b) Posicast command

(c) System output (dashed is uncompensated)Fig. 1. Natural response (a), Posicast command (b) and resulting output (c)

Posicast splits the original step input command into two parts, as illustrated in Fig. 1(b). The first part is a scaled step that causes the first peak of the oscillatory response to precisely meet the desired final value. The second part of the reshaped input is full scale and time-delayed to precisely cancel the remaining oscillatory response, thus causing the system output to stay at the desired value. Such is the idea behind half-cycle Posicast, which can be modeled using just the two parameters and Td. The resulting system output is sketched in Fig. 1(c); the uncompensated output is also shown for comparison.

A. The Analytical Model of PosicastOne block diagram interpretation of the half-cycle Posicast controller is shown in Fig. 3(a). The model has two forward paths. The upper path is that of the original, uncompensated command input. In the lower path, a portion of the original command is initially subtracted, so that the peak of the response will not overshoot the desired final value. Precisely a half cycle later, the command is fully restored to cancel oscillations and maintain the final value. The transfer function is given by the function 1 + P(s), where P(s) is given by:

Fig. 3. Block diagrams for half cycle Posicast

(1)

Posicast can be easily constructed in MATLABs SIMULINK environment by using the transport delay block. A sample diagram is shown in Fig. 3(b)

B. Frequency Domain Analysis of PosicastHalf-cycle Posicast is equivalent to an all-zero filter, with an infinite set of zeros spaced at odd multiples of the damped natural frequency. Solving for the roots of 1+P(s) = 0, the real part of the zeros is given by:..(2)and the imaginary part is given by:.(3)

The frequency response of Posicast with = 0.8 and Td = 1 is shown in Fig. 4. The first pair of zeros cancels the dominant pair of poles in the lightly damped system.

Fig. 4. Posicast frequency response for _ = 0.8, Td = 1

A BRIEF HISTORY OF POSICAST RESEARCH AND APPLICATIONSThe invention of Posicast control is due to Prof. Otto J. M. Smith (currently Professor Emeritus University of California at Berkeley), who described the basic principles in the Sept. 1957 Proceedings of the IRE (Institute of Radio Engineers, forerunner of todays IEEE). Prof. Smith, best known for inventing the Smith Predictor for control of systems having time delay, also described Posicast in his 1958 textbook on feedback control.A decade later, Gerald Cook, then a student at the Massachusetts Institute of Technology (MIT), published an article in the IEEE Transactions on Automatic Control, in which he described application of half-cycle Posicast to vibrating structures. Cook offered an excellent frequency domain interpretation for the Posicast element. An example application of Posicast is the suppression of vibrations on a guided missile launcher. Nearly twenty years later, Prof. Cook presented additional variations of Posicast, with application to the control of flexible structures.

Fig. 5. Posicast within a feedback system

The technique of preshaping command inputs to minimize structural vibrations was also being studied independently by mechanical engineers during this time. Dr. Neil C. Singer founded a company in 1989 to commercialize results of MIT research. The following year, he and Warren Seering described the underlying theory in terms of properly spaced impulse responses, and applied the method to suppress end point vibrations on Draper Labs Remote Manipulator System simulator. Cook would later point out that their technique is theoretically equivalent to Posicast. Sensitivity to modeling errors are reduced by Singer and Seerings methods, which can be interpreted as higher order forms of Posicast. The solution can be interpreted as placing multiple zeros in the vicinity of the lightly damped poles of the flexible system. A U.S. patent has also been separately issued for what appears to be a related concept called staggered Posicast, in which multiple Posicast filters, each having distinct delay values, are chosen to attenuate resonances across a finite range. In addition, a current search of the IEEE library via IEEEX plorereveals a large body of robotics research literature describing the concept and application of input preshaping.From its conception and through the past 40-plus years, Posicast and related interpretations have the common characteristic of being feedforward control techniques. Higher order and multilevel variations can improve robustness, but classical Posicast generally suffers from sensitivity to modeling errors.

PR CONTROLThe form of PR control is shown below... (4.41)Before investigating the digital form, it is better to go over the general form of PR shown below.. (4.42)The implementation of P and R can be done separately due to the linearity. Hence, it is useful to check the digital form of R.By implementing the bi-linear (Tustin) transformation in (4.32), the digital form would be..(4.43)(4.44)(4.45)We see that by implementing the ideal R in (4.44), only the term b2 has an implementation error. We may assume the error is equivalently from the denominator of b2; then we have(4.46)

Assuming the error from denominator is when implementing the digital form (4.47)The error of implementing ideal R can be regarded as implementing digital form of (4.42) with a specific k. So, the error would be from the parameter of k (4.48)Making (4.48) equal to (4.47) leads to (4.49)Therefore, when we implement the digital form of ideal resonant controller, a small error results from the fact that we implement a general form of resonant controller with k, which is proportional to Ts and inversely-proportional to Tf. However, the gain at resonant frequency is highly related to parameter k. As shown below, a smaller k can degrade the gain dramatically.

Figure 4.24: Relationship between gain and kTherefore, although the PR can achieve the same performance as a single-phase d-q frame PI controller, implementation error can result in a big impact to the real performance. The steady-state error would be bigger with bigger error.

MODELLING OF A CASE STUDY

DVR COMPONENTS AND ITS BASIC OPERATIONAL PRINCIPLEA. DVR ComponentsA typical DVR-connected distribution system is shown in Fig. 1, where the DVR consists of essentially a series-connected injection transformer, a voltage-source inverter, an inverter output filter, and an energy storage device that is connected to the dc link. Before injecting the inverter output to the system, it must be filtered so that harmonics due to switching function in the inverter are eliminated. It should be noted that when using the DVR in real situations, the injection transformer will be connected in parallel with a bypass switch (Fig. 1). When there is no disturbances in voltage, the injection transformer (hence, the DVR) will be short circuited by this switch to minimize losses and maximize cost effectiveness. Also, this switch can be in the form of two parallel thyristors, as they have high on and off speed. A financial assessment of voltage sag events and use of flexible ac transmission systems (FACTS) devices, such as DVR, to mitigate them. It is obvious that the flexibility of the DVR output depends on the switching accuracy of the pulse width modulation (PWM) scheme and the control method. The PWM generates sinusoidal signals by comparing a sinusoidal wave with a saw tooth wave and sending appropriate signals to the inverter switches.

Fig. 1. Typical DVR-connected distribution system.

B. Basic Operational Principle of DVRThe DVR system shown in Fig. 1, controls the load voltage by injecting an appropriate voltage phasor (vdvr) in series with the system using the injection series transformer. In most of the sag Compensation techniques, it is necessary that during compensation, the DVR injects some active power to the system. Therefore, the capacity of the storage unit can be a limiting factor in compensation, especially during long-term voltage sags.

Fig. 2. Phasor diagram of the electrical conditions during a voltage sag.

The phasor diagram in Fig. 2, shows the electrical conditions during voltage sag, where, for clarity, only one phase is shown. Voltages V1, V2, and Vdvr are the source-side voltage, the loadside voltage, and the DVR injected voltage, respectively. Also, the operators I, , , and are the load current, the load power factor angle, the source phase voltage angle, and the voltage phase advance angle, respectively. It should be noted that in addition to the in-phase injection technique, another technique, namely the phase advance voltage compensation technique is also used. One of the advantages of this method over the in-phase method is that less active power should be transferred from the storage unit to the distribution system. This results in compensation for deeper sags or sags with longer durations.Due to the existence of semiconductor switches in the DVR inverter, this piece of equipment is nonlinear. However, the state equations can be linearized using linearization techniques. The dynamic characteristic of the DVR is influenced by the filter and the load. Although the modeling of the filter (that usually is a simple LC circuit) is easy to do, the load modeling is not as simple because the load can vary from a linear time invariant one to a nonlinear time-variant one. In this paper, the simulations are performed with two types of loads: 1) a constant power load and 2) a motor load.

Fig. 3. Distribution system with the DVR.As Fig. 3 shows, the load voltage is regulated by the DVR through injecting Vdvr. For simplicity, the bypass switch shown in Fig. 1 is not presented in this figure. Here, it is assumed that the load has a resistance Rl and an inductance Ll. The DVR harmonic filter has an inductance of Lf, a resistance of Rf , and a capacitance of Cf . Also, the DVR injection transformer has a combined winding resistance of Rt , a leakage inductance of Lt , and turns ratio of 1:n.

Fig. 4. Open-loop control using the Posicast controller.

The Posicast controller is used in order to improve the transient response. Fig. 4 shows a typical control block diagram of the DVR. Note that because in real situations, we are dealing with multiple feeders connected to a common bus, namely the Point of Common Coupling (PCC), from now on,V1 and V2 will be replaced with VPCC and , respectively, to make a generalized sense. As shown in the figure, in the open-loop control, the voltage on the source side of the DVR is compared with a load-side reference voltage (VL*) so that the necessary injection voltage V*inv is derived. A simple method to continue is to feed the error signal into the PWM inverter of the DVR. But the problem with this is that the transient oscillations initiated at the start instant from the voltage sag could not be damped sufficiently. To improve the damping, as shown in Fig. 4, the Posicast controller can be used just before transferring the signal to the PWM inverter of the DVR. The transfer function of the controller can be described as follows:

.(1)where and Td are the step response overshoot and the period of damped response signal, respectively. It should be noted that the Posicast controller has limited high-frequency gain; hence, low sensitivity to noise.To find the appropriate values of and Td , first the DVR model will be derived according to Fig. 3, as follows:..(2)Then, according to (2) and the definitions of damping and the delay time in the control literature, and Td are derived as follows:.(3)

Fig. 5. Multiloop control using the Posicast and P+Resonant controllers.

The Posicast controller works by pole elimination and proper regulation of its parameters is necessary. For this reason, it is sensitive to inaccurate information of the system damping resonance frequency. To decrease this sensitivity, as is shown in Fig. 5, the open-loop controller can be converted to a closed loop controller by adding a multiloop feedback path parallel to the existing feedforward path. Inclusion of a feedforward and a feedback path is commonly referred to as two-degrees-of freedom (2-DOF) control in the literature. As the name implies, 2-DOF control provides a DOF for ensuring fast dynamic tracking through the feedforward path and a second degree of freedom for the independent tuning of the system disturbance compensation through the feedback path. The feedback path consists of an outer voltage loop and a fast inner current loop. To eliminate the steady-state voltage tracking error (V*L-VL), a computationally less intensive P+Resonant compensator is added to the outer voltage loop. The ideal P+Resonant compensator can be mathematically expressed as.(4)where KP and KI are gain constants and is the controller resonant frequency. Theoretically, the resonant controller compensates by introducing an infinite gain at the resonant frequency of 50 Hz (Fig. 6) to force the steady-state voltage error to zero. The ideal resonant controller, however, acts like a network with an infinite quality factor, which is not realizable in practice. A more practical (nonideal) compensator is therefore used here, and is expressed as

Fig. 6. Typical magnitude responses of the (a) Ideal and (b) nonideal P+Resonantcontroller.

PROPOSED MULTIFUNCTIONAL DVRIn addition to the aforementioned capabilities of DVR, it can be used in the medium-voltage level (as in Fig. 7) to protect a group of consumers when the cause of disturbance is in the downstream of the DVRs feeder and the large fault current passes through the DVR itself. In this case, the equipment can limit the fault current and protect the loads in parallel feeders until the breaker works and disconnects the faulted feeder.

Fig. 7. DVR connected in a medium-voltage level power system.

The large fault current will cause the PCC voltage to drop and the loads on the other feeders connected to this bus will be affected. Furthermore, if not controlled properly, the DVR might also contribute to this PCC voltage sag in the process of compensating the missing voltage, hence further worsening the fault situation.To limit the fault current, a flux-charge model has been proposed and used to make DVR act like a pure virtual inductance which does not take any real power from the external system and, therefore, protects the dc-link capacitor and battery as shown in Fig. 1. But in this model, the value of the virtual inductance of DVR is a fixed one and the reference of the control loop is the flux of the injection transformer winding, and the PCC voltage is not mentioned in the control loop. In this paper, the PCC voltage is used as the main reference signal and the DVR acts like variable impedance. For this reason, the absorption of real power is harmful for the battery and dc-link capacitor. To solve this problem, impedance including a resistance and an inductance will be connected in parallel with the dc-link capacitor. This capacitor will be separated from the circuit, and the battery will be connected in series with a diode just when the downstream fault occurs so that the power does not enter the battery and the dc-link capacitor. It should be noted here that the inductance is used mainly to prevent large oscillations in the current. The active power mentioned is, therefore, absorbed by the impedance.

PROPOSED METHOD FOR USING THE FLUX-CHARGE MODELIn this part, an algorithm is proposed for the