Abstract:
The invention features a system for connection to a utility power network. The system includes a reactive power compensation device coupled to the network and configured to transfer reactive power between the utility power network and the reactive power compensation device; a capacitor system configured to transfer capacitive reactive power between the utility power network and the capacitor system; an electro-mechanical switch for connecting and disconnecting the capacitor system to the utility power network; an interface associated with the electro-mechanical switch; a controller configured to provide control signals for controlling the electro-mechanical switch; and a communication channel for coupling the controller to the interface associated with the electro-mechanical switch. The electro-mechanical switch, interface, controller, and communication channel together are configured to connect or disconnect the capacitor system from the utility power network within about three line cycles or less of the nominal voltage frequency when a fault condition is detected on the utility power network.

Description:
BACKGROUND OF THE INVENTION 
   This invention relates to electric power utility networks including generating systems, transmission systems, and distribution systems serving loads. 
   To remain competitive, electrical utility companies continually strive to improve system operation and reliability while reducing costs. To meet these challenges, the utility companies are developing techniques for increasing the life of installed equipment, as well as, diagnosing and monitoring their utility networks. Developing these techniques is becoming increasingly important as the size and demands made on the utility power grid continue to increase. A utility power grid is generally considered to include both transmission line and distribution line networks for carrying voltages greater than and less than about 35 kV, respectively. 
   Voltage instability on the utility power grid is a critical problem for the utility industry. In particular, when a fault occurs on the transmission grid, momentary voltage depressions are experienced, which may result in voltage collapse or voltage instability on the grid. In general, such a fault appears as an extremely large load materializing instantly on the transmission system. In response to the appearance of this very large load, the transmission system attempts to deliver a very large current to the load (the fault). Detector circuits associated with circuit breakers on the transmission system detect the overcurrent situation immediately (i.e., within a few milliseconds.) Activation signals from the utility protective relays are sent to the circuit breaker which opens the circuit. The mechanical nature of the circuit breakers generally requires 3–6 cycles (i.e., up to 100 msecs) to open. When the breakers open, the fault is cleared. However, opening of the breakers triggers a sequence of events, which in the extreme can cause that portion of the transmission and distribution system to collapse. Specifically, when the breakers open, the voltage is still low (i.e., almost zero) and, because a portion of the transmission system has in effect been removed, the impedance of the system dramatically increases causing the appearance of an artificially high load. In this state the voltage is depressed and the current serving the load sharply increases. The sharp increase in the current generates enormous losses in the transmission and distribution systems. In some cases, because the load and impedance are high, the voltage on the grid may not return to normal, causing long-term voltage depression and the possible voltage collapse of the entire system. The potential for these voltage instability problems are further exacerbated as load requirements on the grid increase. 
   One approach for addressing this problem is to construct additional transmission lines, thereby negating the effects of the high losses and sharp increase in current flow caused by the opening of the breaker. However, providing such additional lines is expensive and in certain settings extremely difficult. 
   Various equipment and device solutions have also been developed to address these voltage instability and collapse problems, such as SVCs and STATCOMs as described in greater detail below. In general, such devices remove the losses contributing to the huge increase in current by temporarily injecting power into the system. These losses can be both resistive as well as reactive. To understand the difference between resistive and reactive losses, note that the general expression for average power (when waves of voltage and current are sinusoidal), is 
                   V   m     ⁢     I   m       2     ⁢   cos   ⁢           ⁢   θ     ,         
where V m  and I m  represent the peak voltage and current, respectively. Since the maximum value of a sine wave divided by the square root of 2 is the effective value, the equation for average power may be written as:
 
           P   =           V   m       2       ⁢       I   m       2       ⁢   cos   ⁢           ⁢   θ     =     VI   ⁢           ⁢   cos   ⁢           ⁢   θ             
When V is in volts and I is in amperes, the power is expressed in watts. The instantaneous power is:
 
           p   =       [             V   m     ⁢     I   m       2     ⁢   cos   ⁢           ⁢   θ     -           V   m     ⁢     I   m       2     ⁢   cos   ⁢           ⁢   θcos2ωτ       ]     +           V   m     ⁢     I   m       2     ⁢   sin   ⁢           ⁢   θsin2ωτ             
The first two terms of the right side of this equation represent instantaneous real power. When 2ωτ is an odd multiple of π, the value of the real power is
 
                 2   ⁢     V   m     ⁢     I   m       2     ⁢   cos   ⁢           ⁢   θ     =     2   ⁢   VI   ⁢           ⁢   cos   ⁢           ⁢   θ           
When 2ωτ is a multiple of 2π, the real power is 0. Hence real power in a single-phase circuit fluctuates between 0 and 2VI cos π and has an average value of VI cos π. The third term of the right-hand member of the equation represents what is referred to as instantaneous reactive power, or, preferably, instantaneous reactive volt-amperes. Its equation is
 
           px   =       (           V   m     ⁢     I   m       2     ⁢   sin   ⁢           ⁢   θ     )     ⁢   sin   ⁢           ⁢   2   ⁢   ωτ           
Thus instantaneous reactive volt-amperes fluctuate between
 
               +         V   m     ⁢     I   m       2       ⁢   sin   ⁢           ⁢   π   ⁢           ⁢   and     ⁢           -           V   m     ⁢     I   m       2     ⁢   sin   ⁢           ⁢     π   .             
Whereas the average value of the instantaneous reactive volt-amperes is zero, the maximum value is
 
                 V   m     ⁢     I   m       2     ⁢   sin   ⁢           ⁢     π   .           
This is the value referred to when reactive volt-amperes are considered. Hence,
 
   
     
       
         
           Px 
           = 
           
             
               
                 
                   V 
                   m 
                 
                 
                   2 
                 
               
               ⁢ 
               
                 
                   I 
                   m 
                 
                 
                   2 
                 
               
               ⁢ 
               sin 
               ⁢ 
               
                   
               
               ⁢ 
               θ 
             
             = 
             
               VI 
               ⁢ 
               
                   
               
               ⁢ 
               sin 
               ⁢ 
               
                   
               
               ⁢ 
               θ 
             
           
         
       
     
   
   Reactive volt-amperes are expressed in VARs; a term coined from the first letters of the words “volt amperes reactive”. Reactive volt-amperes considered over a period of time represent oscillations of energy between the source and the load. Their function is to supply the energy for magnetic fields and charging condensers, and to transfer this energy back to the source when the magnetic field collapses or when the condenser discharges. Although reactive volt-amperes, as such, require no average energy input to the generators, they do necessitate a certain amount of generator volt-ampere capacity and thereby limit the available power output of the generators. Reactive power is due to quadrature components of voltage and current and as such represents no average power. These additional losses, which increase the required total real power, are generally supplied by an average energy input to the generators. 
   Historically, power utilities address severe voltage stability and control issues on transmission and distribution grids with traditional Static VAR Compensator (SVC) and Static Synchronous Compensator (STATCOM) solutions. A STATCOM is a form of an SVC that uses power electronics (e.g., a voltage sourced inverter) to generate the VARs. 
   Referring to  FIG. 1 , an SVC  100  is shown to include a phase-controlled TCR (Thyristor Controlled Reactor)  102  and a set of TSCs (Thyristor Controlled Capacitors)  104  connected on the secondary side of a coupling transformer  106 . SVC  100  provides reactive power from both TCR  102  and TSCs  104  when a fault is experienced on the utility grid. In particular, TCR  102  and TSCs  104  are connected to transformer via a medium voltage line  108  (12–20 KV). The primary side of transformer  106  is connected to the high voltage transmission line (e.g., &gt;35 KV)  110 . In normal operation, a TSC  104  is in the “on” condition all of the time while a TCR  102  is gated on at a specific phase angle every half-line-cycle to cancel out a portion of the capacitive VAR injection. For small phase angles, the conduction time and therefore the inductive VARs is small. For large phase angle approaching 180 degrees, the TCR  102  is essentially “on” the entire half-cycle and more of the capacitive VARs are canceled. A controller (not shown) provides control signals to the TSCs  104  and gating signals to the TCR  102  to allow for infinite control of VAR output from 0–100% depending on system need. Switching of TCR  102  and TSCs  104  occurs very quickly (e.g., within one-half line cycle) using thyristor switches  116 . The TCR is sized to provide maximum lagging VARs, while the TSCs may be of the same or different sizes (e.g., 25–100 MVAR) to incrementally introduce capacitive VARs to the system. Thus, TCR  102  serves as a variable VAR compensation device while TSCs  104  serve as fixed but incrementally added/subtracted VAR compensation devices. 
   In operation, SVC system  100  regulates voltage at its terminal by controlling the amount of reactive power injected into or absorbed from the utility power system. When system voltage is low, SVC  100  generates reactive power (SVC capacitive). When system voltage is high, it absorbs reactive power (SVC inductive). More specifically, SVC  100  rapidly delivers the reactive power to shift the power angle, thereby raising or lowering the voltage on the network. SVC  100  continuously shifts the power angle in response to dynamic power swings on the transmission network due to changing system conditions. 
   SVC system  100  can also include smaller harmonic filter capacitors  112  (e.g. each 10–30 MVARs) that are always “on” and filter out higher harmonics (e.g., 5 th  and 7 th  order harmonics as tuned by inductors  113  in series with capacitors  112 ) generated by the natural action of the thyristors. SVC system  100  can also be used in conjunction with mechanically-switched capacitors  114  for voltage regulation. 
   Such static VAR compensators provide capacitive reactance for several reasons. First, utility power systems, particularly at the transmission level, are primarily inductive, due to the length of transmission lines and the presence of numerous transformers. Second, many of the largest loads connected to the utility power system are typically inductive. Large motors used, for example, in lumber mills, rock crushing plants, steel mills, and to drive pumps, shift the power factor of the system away from the desired unity level, thereby decreasing the efficiency of the power system. By selecting the proper amount of capacitance and connection location, the capacitor banks can provide a level of control of the line voltage, power factor, or volt-ampere-reactive (VAR) power. Because most inductive loads operate intermittently and cyclically, the correct compensation is generally applied selectively in response to the varying reactive load on the system. 
   SVCs and STATCOM systems have the attribute of being capable of providing rapidly changing VARs needed to regulate voltage and quickly drive post-contingency voltages to acceptable levels. The timeframe required for the solution&#39;s response is on the order of a few line-cycles of AC power (one line cycle is 16.7 mS for 60 Hz AC power systems) even though it is capable of responding on a sub-cycle basis. However, the primary disadvantage of SVC and STATCOM systems is their high cost. 
   SUMMARY OF THE INVENTION 
   The invention features a system and approach for providing dynamic reactive compensation to utility transmission and distribution grids. Reactive compensation is accomplished by injecting capacitive or inductive reactive current in shunt with a utility power network. 
   In one aspect of the invention, a system for connection to a utility power network includes a reactive power compensation device coupled to the network and configured to transfer reactive power between the utility power network and the reactive power compensation device; a capacitor system configured to transfer capacitive reactive power between the utility power network and the capacitor system; an electro-mechanical switch for connecting and disconnecting the capacitor system to the utility power network; an interface associated with the electro-mechanical switch; a controller configured to provide control signals for controlling the electro-mechanical switch; and a communication channel for coupling the controller to the interface associated with the electro-mechanical switch. The electro-mechanical switch, interface, controller, and communication channel together are configured to connect or disconnect the capacitor system from the utility power network within about three line cycles or less of the nominal voltage frequency when a fault condition is detected on the utility power network. 
   Embodiments of these aspects of the invention may include one or more of the following features. The electro-mechanical switch, interface, controller, and communication channel together are configured to connect or disconnect the capacitor system from the utility power network in less than about 80 msecs and preferably less than about 50 msecs from the time the fault condition is detected on the utility power network. 
   The communication channel is a fiber optic channel. The system further includes a number of capacitor systems, each configured to transfer capacitive power between the utility power network and a respective one of the capacitor systems. Each of the capacitor systems is coupled to a corresponding electro-mechanical switch, the controller being configured to operate each capacitor system using a corresponding electro-mechanical switch. In operation and following a predetermined time period, the controller monitors whether to activate or deactivate an additional one of the capacitor systems. The controller is configured to initially activate a predetermined subset of the capacitor systems. 
   The reactive power compensation device (e.g., an inverter) is configured to provide voltage regulation and prevent voltage collapse by quickly providing reactive power to the utility power network so as to rebuild system voltage back to within 10% of the nominal voltage within two seconds, preferably within one second. The reactive power compensation device may include an array of inverters. 
   The system further includes at least one mechanically-switched capacitor or reactor, each configured to transfer capacitive or inductive power to the utility power network in response to a signal from the controller. 
   The controller is configured to, in response to the need to connect at least one capacitor system to the utility power network, activate the reactive power compensation device and, substantially simultaneously, causes the at least one capacitor system to be connected to the utility power network. 
   In another aspect of the invention, a method for stabilizing a utility power network includes the following steps. A reactive power compensation device is electrically coupled to the network and is configured to transfer reactive power between the utility power network and the reactive power compensation device. At least one capacitor system including an electro-mechanical switch is electrically coupled to the network and is configured to transfer capacitive power between the utility power network and the at least one capacitor system. A fault condition is detected on the utility power network. In response to detecting the fault condition, at least one electro-mechanical switch is operated within about three line cycles or less of the nominal voltage frequency. 
   Embodiments of this aspect of the invention may include one or more of the following features. A controller is coupled to the electro-mechanical switch with a fiber optic communication channel. A plurality of capacitor systems is coupled to the utility power network, each associated with a corresponding electro-mechanical switch and each configured to transfer capacitive power between the utility power network and a respective one of the plurality of capacitor systems. A controller monitors whether to activate an additional one or a preset of the capacitor systems bank or deactivate one or a preset of the capacitor systems. 
   The controller controls the reactive power compensation device to quickly provide reactive power to the utility power network so as to boost voltage to 0.90 P.U. of the nominal line voltage within two seconds, preferably within one second. The reactive power compensation device comprises at least one inverter or an array of inverters. 
   In response to the need to connect the at least one capacitor system to the utility power network, the reactive power compensation device is activated and, substantially simultaneously, the at least one capacitor system is connected to the utility power network. Prior to detecting a fault condition on the utility power network, the reactive power compensation device is controlled to provide voltage regulation of the utility power network. Controlling the reactive power compensation to provide voltage regulation includes deactivating at least one of the capacitor systems if the nominal voltage on the utility power network is greater than a predetermined upper threshold (e.g., 1.04 P.U.). Controlling the reactive power compensation to provide voltage regulation also includes activating at least one of the capacitor systems if the nominal voltage on the utility power network is less than a predetermined lower threshold (e.g., 1.0 P.U.). 
   Deactivating the reactive power compensation device if bucking VARS are required and if a predetermined capacitor timing period (e.g., in a range between one second and several minutes) has expired. The capacitor timing period is dependent on the reactive power output of the reactive power compensation device. Activating the reactive power compensation device if boosting VARS are required and if a predetermined capacitor timing period has expired. If the nominal voltage on the utility power network is less than a predetermined fast control threshold (e.g., &gt;10% of the nominal voltage): 1) activating at least one of the plurality of capacitor systems; and 2) controlling the reactive power compensation device to increase VAR injection from the reactive power compensation device. 
   The method further includes controlling the reactive power compensation device to increase VAR injection from the reactive power compensation device if boosting VARs are required, controlling the reactive power compensation device to decrease VAR injection from the reactive power compensation device if boosting VARs are not required and if the nominal voltage is less than a predetermined overvoltage threshold (e.g., 5% of the nominal voltage); and controlling the reactive power compensation device to increase VAR injection from the reactive power compensation device if boosting VARs are not required and if the nominal voltage is greater than the predetermined overvoltage threshold. 
   The method further includes deactivating at least one of the capacitor systems if the nominal voltage is greater than a fast capacitor removal threshold (e.g., &gt;5% of the nominal voltage); and activating at least one of the capacitor systems if the nominal voltage is less than the predetermined fast control threshold. 
   The system and method are capable of attenuating rapid voltage variations and for providing post-fault voltage support to mitigate any tendency for voltage collapse. In addition to acting as a fast transient voltage support device, the system is also capable of regulating voltage at a point on the transmission or distribution grid and minimizing transients imposed on the fundamental waveform of a normal voltage carried on a utility power network when a reactive power source (e.g., capacitor bank) is connected to the utility power network. By integrating the dynamic VAR output of the reactive power compensation device (e.g., inverters) with very fast (e.g., 24 msecs) mechanically switched capacitor and reactor banks, the system becomes a very economical alternative to SVC&#39;s and equally effective at solving common transmission grid problems such as voltage instability and voltage regulation. SVC&#39;s and STATCOMs are faster than necessary to solve these problems and are very costly. Conventional mechanically switched reactive devices, while of acceptable speed (&gt;100 mS) for voltage regulation, are too slow to solve voltage instability. The invention addresses the speed limitations of conventional mechanical switches and uses them provide the bulk of the reactive power while the reactive power compensation device (e.g., inverters) provides a small (10–25%) but overly fast amount of reactive power. The reactive power compensation device generally only moves the voltage a few percent at rated output and thus the opportunity for unstable behavior and/or oscillations is significantly reduced. Thus, although the system of the invention has the same range as an SVC, the control of capacitors for slow control makes it look much smaller in the dynamic sense and hence precludes many of the instability problems. Further, because the cost of the system is about 25% less then a comparably sized SVC, the invention provides an economic alternative to STATCOM—based and SVC-based systems. The invention also uses electro-mechanical switches that are considerably less expensive than conventional thyristor switches used in an SVC. 
   These and other features and advantages of the invention will be apparent from the following description of a presently preferred embodiment and the claims. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a block diagram of a conventional SVC system. 
       FIG. 2  is a block diagram of a dynamic voltage system including D-VAR® statcoms and fast-switched capacitor banks. 
       FIG. 3  is a block diagram of the D-VAR® statcoms of the dynamic voltage system of  FIG. 2 . 
       FIG. 4  is a block diagram of a fast-switched capacitor bank and the communication link of  FIG. 2 . 
       FIG. 5  is a graph illustrating the relationship between VAR output as a function of time for the dynamic voltage system of  FIG. 2 . 
       FIG. 6  is a flow diagram illustrating the general steps for operating the dynamic voltage system. 
       FIGS. 7A–7C  are flow diagrams illustrating the general steps for operating the dynamic voltage system in slow mode. 
       FIGS. 8A–8C  are flow diagrams illustrating the general steps for operating the dynamic voltage system in fast mode. 
   

   DETAILED DESCRIPTION 
   Referring to  FIG. 2 , a dynamic voltage system  10  is shown connected in shunt with a transmission line  110  of a utility power network via a first transformer  12 , which steps down the higher voltage (e.g., greater than 35 kV carried on transmission line  110  to a lower voltage, here 34.5 kV, of a medium voltage bus  108 . Dynamic voltage system  10  includes, in this embodiment, a pair of D-VAR® statcom systems  30 , each of which are coupled to an internal bus  14  with summing transformers  32 . D-VAR® statcom systems  30  are available from American Superconductor Corporation, Westboro, Mass. Because each D-VAR® statcom system  30  has a nominal 480 VAC output, two stages of transformation (transformers  12  and  32 ) to interface to a high voltage transmission system are used. 
   Dynamic voltage system  10  also includes a shunt reactor  40  and, in this embodiment, four capacitor banks  50   a , each coupled to internal bus  14 . Shunt reactor  40  provides negative (inductive) VARs over and above those provided by D-VAR® statcom systems  30  and capacitor banks  50   a  are capable of generating 20 MVAR and 25 MVARs of reactance per bank, respectively. Shunt reactor  40  and capacitor banks  50   a  are coupled through internal bus  14  to medium voltage bus  108  through appropriately sized circuit breakers  19 . Dynamic voltage system  10  further includes, in this embodiment, a pair of capacitor banks  50   b , each coupled to transmission line  110 . Capacitor banks  50   b  are capable of generating  50  MVARs of reactance per bank, about twice as much MVAR capacity as capacitor banks  50   a . Because capacitor banks  50   b  are connected directly to the higher voltage transmission bus  110  they provide a more cost-effective way of injecting a greater amount of capacitive reactance to the utility power network in the event of a fault. 
   D-VAR® statcoms  30 , reactor  40  and capacitor banks  50   a ,  50   b  are all controlled by a DVC controller  60  in response to voltage fluctuations sensed over signal lines  18 , which are connected to the utility power network. In this embodiment, capacitor banks  50   a ,  50   b  may be used for voltage regulation in conjunction with “slower” mechanically-switched capacitor (MSCs) banks (i.e., switching times&gt;6 line cycles). For example, capacitor banks  114 , as shown in  FIG. 1 , represent the type of mechanically-switched capacitors which may or may not already be provided for voltage regulation by utility companies at a given substation. Utility MSCs can be controlled for long-term voltage regulation through a supervisory control and data acquisition (SCADA) interface. However, mechanically-switched capacitors  114  of the type shown in  FIG. 1  are too slow for preventing voltage collapse. 
   In general, and as will be described in greater detail below, D-VAR® statcom systems  30  generate the dynamic, variable VAR component of the solution while capacitor banks  50   a ,  50   b  provide the incrementally or stepped capacitive VAR component of the system and shunt reactor  40  provides the incrementally or stepped inductive VAR component of the system. It should be appreciated that for purposes of clarity, only one of the three phases of the power system are shown. Also, certain components (e.g., fuses, protective relays, breakers) typically used in utility power systems are not shown in  FIG. 2 . 
   Referring to  FIG. 3 , each D-VAR® statcom system  30  which, in this example, includes thirty two 250 kVA inverter modules  36  whose outputs are combined on the medium-voltage side of the power transformers to yield the desired system performance. Depending on the implementation, suitable inverter modules include Power Module™ PM250, and Power Module™ PM1000, both of which are available from American Superconductor Corporation, Westboro, Mass. The inverter modules  36  are coupled to the secondary side of summing transformers  32  through circuit breakers  34 . 
   Referring again to  FIG. 2  and  FIG. 4 , to effectively address fault conditions sensed by controller  60 , capacitor banks  50   a  and  50   b , and reactor  40  must be capable of being added and removed as fast as possible to the intermediate (distribution voltage) and/or transmission voltage bus. Traditional circuit breakers, motor operated switches, or fast switches controlled through conventional utility signaling means are too slow. To overcome this problem, direct communication from controller  60  to high speed vacuum switches  52  are used to provide necessary trip (open) and close timing. 
   In particular, and as shown in  FIG. 4 , each capacitor bank  50   a ,  50   b  includes one or more capacitors  53 , an inrush suppression reactor  57  and a vacuum switch  52 . Control signals from controller  60  are received over a fiber optic communication line  54  and by a digital interface  56  of vacuum switch  52 . One example of a fiber optic communication line suitable for use is a molded cable having industry standard 62.5/125 micron glass multimode fiber with ST connectors. A capacitor switch having suitable trip and close timing characteristics is the VBU switch, manufactured by Joslyn Hi-Voltage Corporation, Cleveland, Ohio. The Joslyn VBU switch possess trip and close timing characteristics of about 24 msecs or 29 msecs, respectively or 1.5 line cycles at 60 Hz. Each capacitor bank  50   a ,  50   b  includes an inrush suppression reactor  57 . Each inrush suppression reactor  57  is used to limit the “inrush” or current when an additional discharged capacitor bank in parallel is activated with a capacitor bank that has already been activated. 
   Exemplary characteristics of a capacitor switch  52  suitable for use in dynamic voltage system  10  are shown below: 
   
     
       
             
             
             
             
           
         
             
                 
                 
             
           
           
             
                 
               Switch Opening (per pole) 
                 
                 
             
             
                 
               Direct Energy Voltage: 
               40 
               VDC 
             
             
                 
               Close Coil Resistance: 
               2 
               ohms 
             
             
                 
               Trip Timing 
             
             
                 
               from solenoid energization to 
               17 
               ms 
             
             
                 
               contact part 
             
             
                 
               from contact part to full open 
               7 
               ms 
             
             
                 
               total opening time (solenoid 
             
             
                 
               energization to full open) 
             
             
                 
               Direct Energy 
               24 
               ms max. 
             
             
                 
               Capacitor Discharge (reference) 
               24 
               ms max. 
             
             
                 
               Switch Closing (per pole) 
             
             
                 
               Capacitor Discharge Voltage 
               250 
               V 
             
             
                 
               Discharge Capacitance 
               6500 
               mF 
             
             
                 
               Close Timing (from solenoid 
             
             
                 
               energization to contact touch) 
             
             
                 
               Capacitor Discharge 
               28 
               ms max. 
             
             
                 
               20 ms min. 
             
             
                 
               Control Response Time 
             
             
                 
               Analog Controls 
               30 
               ms max. 
             
             
                 
               Digital Controls 
               &lt;1 
               ms. 
             
             
                 
                 
             
           
        
       
     
   
   In a particular embodiment, the normal utility interface (Analog Controls) of the Joslyn VBU switch is bypassed so that communication of the trip (open) and close signals are provided directly to the switch trigger mechanism, thereby avoiding the time delay (30 msec) associated with the conventional analog interface. 
   Referring again to  FIGS. 2 and 4 , each switched capacitor bank  50   a ,  50   b  also includes a saturable reactor that is normally implemented in the form of a potential transformer (PT)  59  having a secondary (not shown) which can be used for diagnostic purposes or left open. When the high speed switch is closed, AC voltage is present on capacitor  53  of capacitor banks  50   a ,  50   b  and PT  59 . When AC voltage is present, capacitor  53  appears to the PT like a high impedance load. But when the capacitor switch  52  opens, trapped charge on the capacitor bank appears like a DC voltage to the PT. At a time typically less than one AC line-cycle (17 mS) after the switch opens, the magnetic core of the PT will saturate. Once saturated, the PT&#39;s impedance drops several orders of magnitude and appears to the capacitor bank like a short circuit and quickly discharges the trapped charge within the capacitor; hence the name “Shorting PT”. Quickly discharging the capacitor makes it available to be switched in by the DVC Controller as needed. 
   With respect to vacuum switches  52 , communication signals “Open” and “Close” carried on communication line  54  are commonly required for fault tolerance. The “Status” signal is optional but almost always present as standard practice. The status signal can be one of many signals. For example, in one embodiment, one signal indicates the status of the switch (open or closed) while a second signal indicates diagnostic information (“Ready” versus “Fault”). In the preferred embodiment, both a status and fault signal are sent back to controller  60  at high speed. This way, if the controller  60  commands switch  52  to close but the status indicates that it did not close, the controller can quickly command a different switch to close. Likewise, if the controller is about to command one switch to close but that switch is reporting a fault, the controller can command a different switch to close instead. Thus, overall functionality and effectiveness of the dynamic voltage system  10  is not compromised in the event of a capacitor or high-speed switch failure. 
   D-VAR® Statcom and Capacitor Control 
   The control of the D-VAR® statcoms  30 , reactor  40  and capacitor banks  50   a ,  50   b  is based on two different modes and time scales. The first time mode is based on providing long term regulation of the voltage on the utility power network while the second time mode is based on the occurrence of a significant fault on the high voltage transmission line  110 . For all of the discussions that follow, approximate values for setpoints and thresholds will be given to facilitate the discussion. It should be appreciated that the user parameters discussed below can be modified depending on the particular application and conditions. Further, with reference to the adding or removing of capacitor banks, it is appreciated that inductive elements can also be added or removed, the net effect on the system voltage being equivalent from a slow steady control perspective. 
   In this context, the term ‘regulation’ is meant to infer the slowly varying control of the voltage on the utility power network. The time scales in this context being on the order of seconds. On the other hand, a fault event requires much faster response times (i.e., within a few line cycles or less). Controller  60  distinguishes between a regulation and a fault condition by comparing the currently measured voltage to the long term average (typically between 0.1 and 10 seconds). If there is a drop in the voltage of greater than 0.10–0.15 PU of the nominal voltage then the “fast” controls take over. Otherwise the system ignores smaller transients than this and responds in a voltage regulation mode. Each of these two modes is described in greater detail below and is understood to be one method of many to achieve the goal. The controller  60  typically receives a voltage signal from a Potential Transformer (PT)  62  ( FIG. 2 ) connected to bus  110 . 
   Voltage Regulation 
   The system has an adjustable band of acceptable voltage (e.g., from 1.00 to 1.04 PU). So long as the measured voltage on the transmission line remains within this band, controller  60  takes no action other than to compute a long term voltage average. If the voltage drifts slowly outside of these limits, controller  60  determines that the DVC statcoms  30  will need to respond. Controller  60  sends control signals to D-VAR® statcoms  30  to cause dynamic VARs to be injected into the network. Controller  60  uses a Proportional plus Integral (PI) control loop algorithm with a target set to prevent the voltage from drifting outside the band. As soon as D-VAR® statcoms  30  start injecting dynamic VARs, a capacitor timer is initiated. If the voltage settles to a value within the band on its own, the D-VAR® statcom  30  simply ramps back down. However, if the utility power network continues to require dynamic VARs for a time period as long or longer than the time needed for the capacitor timer to expire, then controller  60  will request that a capacitor be switched on or off depending on which limit is reached, low or high. Because there can be a very large variability in the delay between the request for a capacitor bank to be switched and the actual switching itself, the system does not “know” when the transient will occur. 
   For example, some of the capacitor banks used for regulation may be located miles away and accessed via a SCADA system while others are local and triggered with the high speed switches. Therefore, after requesting a capacitor bank  50   a ,  50   b , the system continues to hold the voltage at its target level. When a capacitor bank  50   a ,  50   b  is finally switched, the transient will move the voltage toward the center of the band. Since the dynamic voltage system  10  is attempting to hold the edge, this will initially look like a negative error which will be compensated for by the PI control algorithm. As a result the dynamic VAR output of the D-VAR® statcoms  30  will be quickly ramped off. This reduces the net transient of the capacitor switch. At that point, the voltage will be within the band and the D-VAR® statcoms will return to monitoring and wait for the voltage to again exceed one of the band edges. 
   Slow Capacitor Switching Profile 
   The primary control of capacitor banks  50   a ,  50   b  by controller  60  is based on the output of inverters  36  of D-VAR® statcoms  30  either by MVARs or, equivalently, by the current required in the inverters. Ideally, capacitor banks  50   a  are sized to accommodate the full range of voltage regulation and capacitor banks  50   b  are sized to provide the larger VARs required to prevent voltage collapse in conjunction with capacitor banks  50   a . Generally, if the dynamic voltage system  10  requires significant capacitive/boosting MVARs for an extended period, it will want to replace these dynamic VARs with static VARs by switching in a capacitor bank. Conversely, inductive VARs being used to hold the voltage down will eventually call for the removal of a capacitor bank. If all of the capacitors have been previously removed, inductive VARs from D-VAR® statcoms  30  will be used to hold down the voltage until reactor  40  is switched on. It is further appreciated that generally a higher dynamic VAR output will call for a capacitor switching event sooner than an incrementally lesser VAR output, and that there are predetermined minimum and maximum capacitor switching intervals and corresponding VAR levels. 
   Referring to  FIG. 5 , for continuously maintained current outputs of magnitude I 2  boosting or I 4  bucking, a capacitor switch operation will be called for if such an operation is possible (i.e., a capacitor is available to be switched. In such situations, capacitor switching will occur after the output is being commanded for T 2  or T 4  seconds, (points  70 ,  72 ) respectively. Greater current outputs will result in capacitor bank switching transactions occurring sooner, limited by the minimum switching times T 1  or T 3 . Output magnitudes greater than I 1  boosting or I 3  bucking cause capacitor switching at the same minimum switching times. The output-switching time profiles in between the minimum and maximum switching times are linear. 
   Current outputs of magnitudes less than I 2  boosting or I 4  bucking will not result in capacitor switching. Furthermore, the counters that implement the capacitor switching profiles reset when commanded currents drift back into the non-switching zone. All of the time (T) and current (I) values above can be preset. Aside from the limitation that T 2 &gt;T 1  and T 4 &gt;T 3 , there are few absolute restrictions. For reasons of numerical representation, there are implicit minima and maxima for the values. 
   For this system, the minimum delay timer for changing a capacitor should be larger than the maximum duration “transient” event. In other words, one doesn&#39;t want to switch one of the slow regulation capacitors because of a fault on the system. Typically, therefore, this is set to about 5–10 seconds. The output for that time is 1.0 PU or the rated steady state dynamic VAR output. Typically the minimum output requiring a capacitor switch will be a very small value. The time delay for that can be set at several minutes. Thus, if the voltage barely passes outside the band such that the D-VAR® is injecting a minimal amount of VARs then it will do that for several minutes before switching a capacitor. This helps reduce unnecessary capacitor switch events since, in this scenario it is likely that the voltage may return on its own such that all the D-VAR® statcoms need to do is simply ramp back off. 
   PI Control Loop Gains 
   The PI gains are only applicable to the dynamic VAR portion of the output. They are user settable parameters so they can be set based on expected system response. Also, recognize that unlike an SVC, these parameters are primarily used when the control algorithm has determined that a capacitor bank  50   a ,  50   b  needs to be switched in/out for slow regulation control. As discussed above, if capacitor banks  50   a  are appropriately sized, capacitor banks  50   b  may not be required for slow regulation control. The D-VAR® statcoms  30  generally only move the voltage a few percent at rated output and thus the opportunity for unstable behavior and/or oscillations is significantly reduced. Under slow control conditions, the capacitor timer profile will limit the injection/removal of static VARs to the minimum delay time threshold. So, although the DVC has the same range as an SVC, the control of capacitors for slow control makes it look much smaller in the dynamic sense and hence precludes many of the instability problems. 
   Note that the choice of an allowable voltage range from 1.0 to 1.04 PU is integrally coupled to the size of the capacitor banks  50   a ,  50   b  being switched. The key is that when a capacitor bank switches, the voltage should end up near the center of the target band. If the capacitor banks  50   a ,  50   b  are too large or the allowed voltage range is too narrow then there can be a conflict where switching a capacitor bank takes the voltage from one side of the band to the other. If that happens, the dynamic voltage system  10  may then determine that the capacitor bank  50   a ,  50   b  needs to be added, then removed, then added, etc. Thus, by setting the band at twice the expected capacitor switch alone and also accounting for the D-VAR® output, this type of on/off/on type behavior will not occur. However, if the width of the deadband is decreased significantly, then an additional software detection algorithm for this phenomenon will be employed and the system can either generate a warning, an alarm, and/or dynamically increase the deadband under these conditions. The use of a deadband significantly increases the stability of this control system without causing the customer system to deviate from acceptable levels. Other control schemes exist where, in principle, the dynamic voltage system  10  could hold the voltage closer to the midpoint by using dynamic VARs and then capacitor banks only switched when that is no longer sufficient. The penalty is that the dynamic VARs will run virtually non-stop thereby increasing losses. 
   Fast Voltage Sags 
   The majority of the time, dynamic voltage system  10  will not be producing dynamic VARs and the system will be idle with the necessary static VARs on-line to hold the voltage within the deadband. In that mode, dynamic voltage system  10  is also looking for a sag event with a drop in the voltage of greater than 10–15% of the nominal voltage. In that event, the dynamic voltage system  10  immediately takes action to compensate. The dynamic voltage system  10  can optionally use knowledge of the location of the fault with information from current transformers (CTs)  21  (see  FIG. 2 ) placed on each connection to bus  110 , recent measurements of power flow, and the measured depth of the sag event to determine the number of capacitor banks  50   a ,  50   b  that are required to be switched-in quickly. For example, techniques for supplying power to the utility network based on whether the fault is a near fault or a far fault are described in U.S. Pat. No. 6,600,973, entitled, Method And Apparatus For Providing Power To A Utility Network,” which is incorporated herein by reference. Dynamic voltage system  10  uses the fast-switched capacitor banks  50   a ,  50   b  for this purpose. By basing the amount of fast-switched capacitor banks  50   a ,  50   b  on knowledge of the system dynamics, the likelihood of an overshoot at the end of the event is prevented. In addition to the fast-switched capacitor banks  50   a ,  50   b , the system also injects dynamic overload VARs to assist in pushing the voltage up. In this case although truly a closed loop control, this is effectively open loop since the errors are sufficiently large that the PI control loop will simply saturate at the full dynamic VAR overload output. 
   When the fault clears, there are two characteristically different profiles. In one case, the underlying voltage quickly recovers to the pre-fault levels. In the other, the system spends a significant time at depressed levels (&lt;1.0 PU) before slowly recovering. The former case is likely to occur if the load is light or if the fault clears without affecting the system characteristics significantly. In these cases, the system will have switched in only a small fraction of the available capacitors along with the full overload injection of the dynamic VARs. When the voltage reaches the 0.9 PU level, dynamic voltage system  10  quickly starts pulling out the fast-switched capacitor banks  50   a ,  50   b . If the voltage continues to rise, the rate at which the capacitor banks are removed increases until the number of capacitor banks in service are at the pre-fault level. If the voltage increases more than 5% above the pre-fault levels, then the D-VAR® statcoms  30  will also join in by injecting dynamic inductive VARs to reduce the overshoot until the fast-switched capacitor banks  50   a ,  50   b  are physically switched out. If there are additional fast-switched capacitor banks  50   a ,  50   b  that are switched in and the voltage is high, those too will be taken out in a staggered fashion to return the voltage within the deadband. At that point, controller  60  will use its slow control logic to switch any other capacitor banks, including some potentially controlled via a SCADA system such as local or distant slow switched capacitors (e.g., “slow” capacitor switches  114  in  FIG. 1 ), for any fine tuning of the voltage if necessary. The second scenario is that the voltage recovers above a critical level, (e.g., 0.90 PU) but then only slowly recovers to within the deadband. First, controller  60  will use its slow control logic and continue to run. If the D-VAR® statcoms  30  are generating significant VARs for several seconds, the slow control will start adding additional capacitor banks  50   a ,  50   b  to pull that voltage to within the normal band. Once that is achieved it will ramp off and the normal slow control logic will continue to operate. An additional scenario is that the initial insertion of capacitor banks  50   a ,  50   b  is insufficient in getting the voltage back above the critical level. If the voltage does not recover to, for example, 90% of nominal within a fixed time from the switching of the initial capacitor banks then additional banks will be switched in. 
   In the case of a worst-case fault requiring the insertion of significant amounts of fast-switched capacitor banks  50   b , the switching “out” of these banks is carried out earlier once the voltages recover to acceptable levels. For example, one can use capacitor banks of larger size for these worst case scenarios and then switch them back out at a lower level so they do not lead to significant overshoots. 
   In view of the discussion above,  FIGS. 6 ,  7 A– 7 C, and  8 A– 8 C summarize the operation of dynamic voltage system  10 . Referring to  FIG. 6 , operation of dynamic voltage system  10  is based on two different modes: slow control mode ( 200 ) and fast control mode ( 300 ). As described above, slow control mode provides long term regulation of the voltage on the utility power network while the fast control mode is based on the occurrence of a significant fault on the high voltage bus. Thus, controller  60  continuously monitors the utility power network for conditions that cause dynamic voltage system  10  to initiate either or both of slow control mode ( 200 ) and fast control mode ( 300 ). 
   Referring to  FIGS. 7A–7C , in slow control mode, the voltage is monitored and a determination is made as to whether the voltage is greater than a predetermined threshold (e.g., &gt;1.04 PU) or that removal of a capacitor bank was previously initiated ( 202 ). If so, a capacitor bank is removed ( 204 ). If not, a determination is made as to whether the voltage is less than a predetermined threshold (e.g., &lt;1.00 PU) or that addition of a capacitor bank was previously initiated ( 206 ). If so, a capacitor bank is added ( 208 ). If not, the slow control loop is completed and the controller continues to execute code at state  300 . (Referring to  FIG. 7B , to remove a capacitor bank, PI control of dynamic VARs is initiated to achieve the upper target ( 210 ). A determination is made as to whether bucking VARs are required ( 212 ). If not, controller  60  deactivates D-VAR® statcoms  30  and the system is returned to its idle state ( 214 ). If bucking VARs are required, a determination is made to see if the capacitor timer has expired ( 216 ). If so, the capacitor bank is removed ( 218 ) and a determination is made as to whether any capacitor transients are detected ( 220 ). If the capacitor timer has not expired or if no capacitor transients are detected, the slow mode loop (see  FIG. 7A ) is initiated. If capacitor transients are detected, a quick offset of dynamic VARs is provided ( 222 ). 
   Referring to  FIG. 7C , to add a capacitor bank, PI control of dynamic VARs is initiated to achieve the lower target ( 230 ). A determination is made as to whether boosting VARs are required ( 232 ). If not, controller  60  deactivates D-VAR® statcoms  30  and the system is returned to its idle state ( 234 ). If boosting VARs are required, a determination is made to see if the capacitor timer has expired ( 236 ). If so, the capacitor bank is added ( 238 ) and a determination is made as to whether any capacitor transients are detected ( 240 ). If the capacitor timer has not expired or if no capacitor transients are detected, the slow mode loop (see  FIG. 7A ) is initiated. If capacitor transients are detected, a quick offset of dynamic VARs is provided ( 242 ). 
   Referring to  FIG. 8A , in fast control mode, a determination is made as to whether dynamic voltage system  10  is already performing compensation due to a sag ( 302 ). If not, a determination is made as to whether the voltage is less than a fast control threshold ( 304 ) (e.g. delta-V&gt;10–15%). If so, fast sag action is initiated ( 306 ). Referring to  FIG. 8C , sag action is initialized by first estimating the initial capacitor requirements ( 308 ), activating a first one of the capacitor banks  50   a ,  50   b  ( 310 ), and providing PI control of dynamic VARs from D-VAR® statcoms to lower the target ( 312 ). 
   Referring to  FIG. 8B , in a fast sag action, a determination is made as to whether boosting VARs are required ( 320 ). If not, the voltage is monitored to see if it is greater than the predetermined overvoltage threshold (e.g. delta-V&gt;5%) ( 322 ). If not, controller  60  deactivates D-VAR® statcoms  30  and the system is returned to its idle state ( 324 ). If the voltage is greater than the predetermined overvoltage threshold bucking VARs are required, through PI control of dynamic VARs from D-VAR® statcoms to achieve the upper target (e.g., 5–10% above nominal voltage) is provided ( 326 ) to hold the voltage near the original prefault levels. If boosting VARs are not required, PI control of dynamic VARs from D-VAR® statcoms to achieve the lower target is provided ( 328 ). 
   The voltage is then monitored to see if it is greater than the predetermined fast capacitor removal ( 330 ) (e.g. delta-V&gt;5%). If so, controller  60  transmits control signals to remove one of the capacitor banks  50   a ,  50   b  ( 332 ). If not, the voltage is monitored to see if it is less than the lower target (e.g. 0.9 PU) ( 334 ). If so, controller  60  begins a delay counter and a determination is made to see if the capacitor delay has expired ( 336 ). If so, controller  60  transmits control signals to add an additional one of the capacitor banks  50   a ,  50   b  ( 338 ). 
   Still other embodiments are within the scope of the claims. Techniques for minimizing potential transients (e.g., oscillatory “ringing”) imposed on the utility waveform caused by the generally step-like change in voltage when capacitor banks  50   a ,  50   b , as well capacitors  114 , are connected to the utility power network can be used. For example, the techniques described in U.S. Ser. No. 09/449,378, entitled “Reactive Power Compensation to Minimize Step Voltage Changes and Transients,” which is incorporated herein by reference, can be used with dynamic voltage system  10 . In general, during the initial period in which a capacitor bank  50   a ,  50   b  begins delivering reactive power to the utility power network, D-VAR® statcoms  30  and/or reactor  40 , under the control of controller  60 , provide an inductive reactance to counteract the abrupt, step-like introduction of capacitive reactive power from capacitor bank  50   a ,  50   b  on the utility power network. For example, in response to the need to connect a capacitor bank to the utility power network, controller  60  activates the D-VAR® statcoms  30  and/or reactor  40  and, substantially simultaneously, causes the capacitor bank to be connected to the utility power network. Furthermore, D-VAR® statcoms  30  can be controlled to provide additional voltage support to the system prior to capacitive banks  50   a ,  50   b  being connected to the utility power. 
   Further, although high-speed communication line  54  is in the form of a fiber optic line, other forms of high-speed communication links including wired or wireless (e.g., RF) techniques can be used. Further, different numbers and amounts of capacitors or capacitor banks or reactors can be switched on the distribution or transmission voltage bus. In the above embodiment, capacitor banks  50   a  were connected to a medium voltage bus  108  while capacitor banks  50   b  were connected to the higher voltage transmission line  110 . However, in other applications, dynamic voltage system  10  may only require capacitor banks  50   a  on medium voltage bus  108  or only require the higher VAR capacitor banks  50   b  on transmission line  110 . Similarly, different numbers of D-VAR® statcoms can be added to adjust the dynamic portion of the dynamic VAR compensation solution. A custom interface and solenoid driver could be developed for the switch to integrate communication, diagnostic, and protection functions and provide faster switching. The controller could also be augmented to include directional power flow signaling and yield more intelligent capacitor switching algorithms. Switched inductors can be added for solutions requiring lagging VARs or over-voltage regulation.