Patent Publication Number: US-9898062-B2

Title: Systems and methods for protection of components in electrical power delivery systems

Description:
RELATED APPLICATIONS 
     This application is a continuation application of, and claims benefit to co-pending U.S. patent application Ser. No. 12/882,521 filed on 15 Sep. 2010 entitled “Systems and Methods for Protection of Components in Electrical Power Delivery Systems”, which is hereby incorporated by reference in its entirety. 
    
    
     TECHNICAL FIELD 
     This disclosure relates to protection of components in electrical power delivery systems. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a simplified one line diagram of an electric power delivery system. 
         FIG. 2  illustrates an event report showing voltages and currents in a three-phase electric power generation and delivery system. 
         FIG. 3A  illustrates a simplified one line diagram of one system that may implement a protection scheme using synchrophasors for the protection of a plurality of generators. 
         FIG. 3B  illustrates a first measured data set and a second measured data set in comparison to a reference data set. 
         FIG. 4  illustrates a plot of the power output over time of a power generation and distribution system. 
         FIG. 5A  illustrates a plot of the slope and three percent droop characteristics for a system of generators operating in parallel. 
         FIG. 5B  illustrates a plot of the slope and three percent droop characteristics for a system of generators operating in parallel. 
         FIG. 6  illustrates a flow diagram of a method for providing a plurality of local protection blocks and a system protection block. 
         FIG. 7  illustrates a block diagram of an IED configured to implement either a local protection block or a system protection block. 
     
    
    
     Additional aspects and advantages will be apparent from the following detailed description of preferred embodiments, which proceeds with reference to the accompanying drawings. 
     DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
     Electrical power generators in an electrical power generation and distribution system may operate in conjunction with protection systems designed to prevent damage to the electrical power generators that may be caused by certain conditions. Various protection systems may operate at different levels in an electrical power generation and delivery system. For example, one level of generator protection may be provided at the generator level. Generator protection systems that operate at the generator level, however, cannot detect external faults (e.g., a main bus failure). In another example, a generator protection system may operate at a supervisory level. Generator protection systems that operate at the supervisory level, however, may not detect individual generator faults or may not be able to determine the faulty generator in the case of “common-mode faults.” 
     Various embodiments disclosed herein are configured to provide protection to monitored equipment at both a local level and a system level in order to offer more comprehensive protection. In one particular embodiment, the monitored equipment may include one or more generators. The protection system may utilize time-synchronized data in order to analyze data provided by systems having disparate sampling rates, that are monitored by different equipment, and/or equipment that is geographically separated. Various embodiments may be configured to utilize a variety of sampling rates. For example, one embodiment may obtain a time-synchronized data sample every cycle and may generate control signals within 2 to 3 cycles. Considering the response time of typical exciters and governors, these specifications may provide adequate protection to electrical power generators. 
     The systems and methods disclosed herein for protection of electrical generators may be applied to electrical power generation and delivery systems. Certain embodiments disclosed herein may be used in connection with systems capable of functioning as “islanded systems.” As the term is utilized herein, an islanded system comprises any system in which electric power generators continue to provide electrical power in the absence of a connection to an electrical utility grid. For example, an islanded system may include a utility connected system that includes a distributed generation generator, a backup generator, or the like. Many types of facilities may utilize backup electrical systems (e.g., hospitals, oil refineries, gas separation plants, data centers, and the like), and may operate as an islanded system when electrical power from a electrical utility grid is unavailable. Other systems may generate their own power under typical conditions (e.g., an offshore drilling ship, exploration ships, cruise ships, military ships, and remote facilities that are not connected to an electrical utility grid). Finally, the systems and methods disclosed herein may be used in the protection of electrical generators connected to electrical delivery systems (e.g., a utility grid). For example, a protection system may be used at a generation site (e.g., a fossil-fuel generation site, a hydroelectric site, a wind farm, and the like). 
     Islanded electrical power generation and delivery systems may also be referred to as a micro-grid. Micro-grid systems may not have the advantage of being able to receive power from an electric utility grid, and accordingly, micro-grid systems may be designed with redundancies, in order to maximize the availability of electrical power. A micro-grid system may, for example, include multiple electrical generators. Further, the micro-grid system may be configured such that if an electrical generator is taken off-line, either for maintenance or because of a problem, the micro-grid system may continue to operate, although perhaps with reduced capabilities. Various embodiments disclosed herein may provide protection and monitoring of a plurality of electrical power generators, and further, may be configured to implement control actions in order to configure an electric power generation and delivery system. 
     The embodiments disclosed herein are best understood by reference to the drawings, wherein like parts are designated by like numerals throughout. It will be readily understood that the components of the disclosed embodiments, as generally described and illustrated in the figures herein, could be arranged and designed in a wide variety of different configurations. Thus, the following detailed description of the embodiments of the systems and methods of the disclosure is not intended to limit the scope of the disclosure, as claimed, but is merely representative of possible embodiments of the disclosure. In addition, the steps of a method do not necessarily need to be executed in any specific order, or even sequentially, nor need the steps be executed only once, unless otherwise specified. 
     In some cases, well-known features, structures or operations are not shown or described in detail. Furthermore, the described features, structures, or operations may be combined in any suitable manner in one or more embodiments. It will also be readily understood that the components of the embodiments, as generally described and illustrated in the figures herein, could be arranged and designed in a wide variety of different configurations. 
     Several aspects of the embodiments described are illustrated as software modules or components. As used herein, a software module or component may include any type of computer instruction or computer executable code located within a computer-readable device that is operable in conjunction with appropriate hardware to implement the programmed instructions. A software module or component may, for instance, comprise one or more physical or logical blocks of computer instructions, which may be organized as a routine, program, object, component, data structure, etc., that performs one or more tasks or implements particular abstract data types. 
     In certain embodiments, a particular software module or component may comprise disparate instructions stored in different locations of a computer-readable device, which together implement the described functionality of the module. Indeed, a module or component may comprise a single instruction or many instructions, and may be distributed over several different code segments, among different programs, and across several memory devices. Some embodiments may be practiced in a distributed computing environment where tasks are performed by remote processing devices linked through a communications network. In a distributed computing environment, software modules or components may be located in local and/or remote memory storage devices. In addition, data being tied or rendered together in a database record may be resident in the same memory device, or across several memory devices, and may be linked together in fields of a record in a database across a network. 
     Embodiments may be provided as a computer program product including a machine-readable storage medium having stored thereon instructions that may be used to program a computer (or other electronic device) to perform processes described herein. The machine-readable storage medium may include, but is not limited to, hard drives, floppy diskettes, optical disks, CD-ROMs, DVD-ROMs, ROMs, RAMs, EPROMs, EEPROMs, magnetic or optical cards, solid-state memory devices, or other types of machine-readable media suitable for storing electronic instructions. 
       FIG. 1  illustrates a simplified one line diagram of an electric power generation and delivery system  100 . In the configuration illustrated in  FIG. 1 , common-mode faults may result in a blackout of system  100 . As the term is used herein, a common-mode fault refers to one root problem that manifests with multiple symptoms. In other words, one underlying event results in the disruption of two or more components. 
     In a variety of circumstances, undesirable electrical system outages can result in loss of revenue and other adverse consequences. The present disclosure specifically addresses a variety of possible faults, including failure or misoperation of generator exciters and governors, islanding of defective generators, slow fault detection, and clearing of wrong machinery. One of skill in the art will recognize a variety of other types of faults may be addressed by the systems and methods disclosed herein. 
     System  100 , and variations thereof, may be utilized in a variety of applications, including but not limited to any application benefiting from a high reliability power generation and delivery system. In one particular embodiment, system  100  may be utilized in connection with a dynamic positioning vessel. In such embodiments, undesirable electrical system outages can result in significant revenue losses, increased risk of an environmental incident, and damage to public opinion of the industry. In another embodiment, system  100 , and variations thereof, may be used as a backup power source for a variety of applications. 
     System  100  includes, among other things, generators  150 ,  151 ,  152 , and  153 , each of which is configured to generate a sinusoidal waveform. Generators  150 - 153  may be driven by a variety of sources, including two- and four-cycle diesel engines, combustion turbines, steam turbines, wind turbines, hydro-electric turbines, and the like. Although illustrated as a one-line diagram, electric power delivery system  100  may represent a three phase power system.  FIG. 1  illustrates a single phase system for simplicity. 
     Generators  150 - 153  may be connected to an electrical bus  140 . Electrical bus  140  may comprise a first bus segment  140   a  and a second bus segment  140   b . First bus segment  140   a  may be selectively connected to second bus  140   b  by a breaker  142 . As illustrated, generators  150 - 151  may be connected to first bus segment  140   a , and generators  152 - 153  may be connected to second bus segment  140   b . Generators  150 - 153  may be selectively connected to electrical bus  140  by breakers  130 - 133 . 
     IEDs  160 - 164  as shown in  FIG. 1 , may be configured to control, monitor, protect and/or automate the operation of system  100 . Generators  150 - 153  may be in electrical communication with IEDs  160 - 163 , respectively, while IED  164  is in communication with breaker  142 . As used herein, the term IED refers to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within an electric power system. Such devices may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, motor drives, and the like. IEDs gather status information from one or more pieces of monitored equipment. IEDs may receive information concerning monitored equipment using sensors, transducers, actuators, and the like. 
     IEDs  160 - 164  may also gather and transmit information about monitored equipment using current transformers (CTs)  190 ,  191 ,  192 , and  193 , and potential transformers (PTs)  120 ,  121 ,  122 , and  123 . IEDs may be configured to monitor and communicate information, such as voltages, currents, equipment status, temperature, frequency, pressure, density, infrared absorption, radio-frequency information, partial pressures, viscosity, speed, rotational velocity, mass, switch status, valve status, circuit breaker status, tap status, meter readings, and the like. IEDs may also be configured to communicate calculations, such as phasors (which may or may not be time-synchronized as synchrophasors), events, fault distances, differentials, impedances, reactances, frequencies, and the like. IEDs may also communicate settings information, IED identification information, communications information, status information, alarm information, and the like. Information of the types listed above, or more generally, information about the status of monitored equipment is referred to as monitored equipment data. 
     IEDs  160 - 164  may also issue control instructions to monitored equipment in order to control various aspects relating to the monitored equipment. For example, an IED may be in communication with a circuit breaker (e.g., IED  164  and breaker  142 ), and may be capable of sending an instruction to open and/or close the circuit breaker, thus connecting or disconnecting a portion of system  100 . In another example, an IED may be in communication with a recloser and capable of controlling reclosing operations. In another example, an IED may be in communication with a voltage regulator and capable of instructing the voltage regulator to tap up and/or down. Other examples of control instructions that may be implemented using IEDs may be known to one having skill in the art, but are not listed here. Information of the types listed above, or more generally, information or instructions directing an IED or other device or equipment to perform a certain action are referred to as control instructions. 
     IEDs  160 - 164  may be linked together using a data network  110 , and may further be linked to a central monitoring system, such as a supervisory control and data acquisition (“SCADA”) system  182 , an information system  184 , or digital control system (“DCS”)  180 . The embodiment of  FIG. 1  illustrates a star topology having access controller  172  at its center, however, other topologies are also contemplated. For example IEDs  160 - 164  may be connected directly to SCADA system  182  or DCS system  180 . The data communications network of  FIG. 1  may include a variety of network technologies, and may comprise network devices such as modems, routers, firewalls, virtual private network servers, and the like. IEDs and other network devices are connected to the communications network through a network interface. 
     Data regarding the operation of electric power generation and delivery system  100  may be displayed using local Human-machine interface (“HMI”)  186 . In various embodiments, local HMI  186  may be used by one or more operators to observe various indicators and parameters of the status of electric power generation and delivery system  100 . Further, local HMI  186  may provide visual alarms, as necessitated by conditions. 
     An information system  184  may also receive data from access controller  172 . Information system  184  may be utilized in various embodiments to develop customized features suited for a variety of unique applications. For example information system  184  may be utilized to program electric power generation and delivery system  100  to notify key personnel in case of critical alarms and to send to such personnel relevant information. 
     Data generated by electric power generation and delivery system  100  may be recorded in a data archive. In one embodiment, data received by access controller  172  may be compiled into archive sequence of events (“SOE”) records. SOE records may be stored, for example, in comma-separated value files. Each value in the SOE record may be associated with a time stamp. The time stamp may be based upon a time signal provided by common time source  188 . In one embodiment, and ACSELERATOR Report Server® software, model no. SEL-5040, may be used to archive data and generate event reports based on the data. In various embodiments, SOE records may include oscillography for both analog and digital signals. Archived data may be used in post-event analysis and/or optimization of electric power generation and delivery system  100 . 
     In certain embodiments, including the embodiment illustrated in  FIG. 1 , communication among various IEDs and/or higher level systems (e.g., SCADA system  182  or IS  184 ) may be facilitated by access controller  172 . Access controller  172  may also be referred to as an IED, a central IED, or access controller. In various embodiments, access controller  172  may be embodied as the SEL-2020, SEL-2030, SEL-2032, SEL-3332, SEL-3378, or SEL-3530 available from Schweitzer Engineering Laboratories, Inc. of Pullman, Wash. (“Schweitzer Engineering”), and also as described in U.S. Pat. Nos. 5,680,324, 7,630,863, and U.S. Patent Application Publication No. 2009/0254655, the entireties of which are incorporated herein by reference. 
     Access controller  172  may further be in communication with vector processor  174 . Vector processor  174  may be configured to receive data via data network  110  and to process or pre-process that data for use by access controller  172 . Vector processor  174 , and various components, may be embodied as model nos. SEL-3306, SEL-3378, SEL-3354, and SEL-3530 available from Schweitzer Engineering and also described in U.S. Pat. Nos. 7,698,555, 7,630,863, and 5,680,324, and US Patent Application Publication Nos. 2009/0088990, 2009/0125158, 2009/0099798 and 2010/0002348. In certain embodiments, access controller  172  and vector processor  174  may be combined into a single device, such as model no. SEL-3378 available from Schweitzer Engineering. Access controller  172  may also be in communication with access controller  170 . Although not shown in  FIG. 1 , access controller  170  may be connected to other devices and systems. Access controller  172  and access controller  170  may exchange information about the respective systems in order to enable coordination on a larger scale. 
     System  100  includes a local protection block  178  and a system protection block  176 . Local protection block  178  communicates with system protection block  176 . In certain embodiments, communication within local protection block  178  may use direct fiber relay-to-relay or using IEC 61850 protocol using Ethernet. Communication between local protection block  178  and system protection block  176  may also use direct fiber relay-to-relay communications under the IEC 61850 protocol using Ethernet. System protection block  176  may receive and process relevant information from local protection block  178  and may provide control and decisions system-level protection actions. 
     Local protection block  178  includes IEDs  160 - 163  and provides various types of local protection actions in connection with generators  150 - 153 . Although in the illustrated embodiment local protection block  178  only protects a specific type of monitored equipment (i.e., generators  150 - 153 ), protection of other types of monitored equipment is also contemplated. For example, system protection block  176  may be configured to protect a feeder, a bus, a motor, or a transformer. 
     While only one IED is associated with each generator in the illustrated embodiment, in alternate embodiments, if redundancy is desired, more than one IED may be associated with one or more generators. In various embodiments, local protection block  178  may be configured to perform a variety of types of local-level protection actions, including: excess or reverse power protection, reactive power protection, differential power protection, loss of excitation protection, grounding brush lift-off detection, out of step protection, resistance temperature detector protection, trip-coil monitoring, current/voltage unbalance protection, overcurrent protection, phase reversal protection, negative sequence protection, under-voltage and over-voltage protection, under-frequency and over-frequency protection. Certain embodiments may offer each of the preceding types of protections, while other embodiments may offer a subset of the protections. 
     System protection block  176  may provide a variety of types of system-level protection. System-level protection actions may include, for example, common-mode fault detection and resolution, load-dependent start or stop, generator running order selection, load shedding, heavy-consumer start block, blackout start and recovery, generator control, and manual override. In various embodiments when system  100  is operating at less than full generating capacity, or where system  100  is providing backup power during a power outage, a load-shedding scheme may be enabled. The load-shedding scheme may adjust load requirements to match generation capacity. The load-shedding scheme may be designed to include a priority scheme, in which lower priority loads are shed before higher priority loads. 
     In operation, data may be exchanged between local protection block  178  and system protection block  176 ; however, local protection block  178  may continue to provide protection to generators  150 - 153  in the event of a loss of communication between local protection block  178  and system protection block  176 . In the event of a loss of communication, IEDs  160 - 163  may continue to provide local protection to generators  150 - 153 , respectively. Any type of fault detection or protection action that can be monitored or generated by IEDs  160 - 163  may be implemented by local protection block  178  during an interruption in communication. Local protection block  178  and system protection block  176  may provide some redundant protection features to generators  150 - 153 . 
     In various embodiments DCS  180  or SCADA system  182  may offer an additional layer of control. DCS system  180  and/or SCADA  182  may receive data feeds from access controller  172 , or in alternative embodiments directly from IEDs  160 - 164 . Access controller  172  may operate autonomously from DCS system  180  and/or SCADA system  182 . In other words, access controller  172  need not depend on DCS system  180  or SCADA system  182 . 
     In various applications, a protection scheme provided by electric power generation and delivery system  100  may be designed to provide any of the following functions: blocking protection, low impedance protection, or high impedance protection. A low impedance protection scheme may be appropriate where the protection scheme operates in less than 1 cycle. In one particular embodiment, a low impedance relay, such as the SEL-487B Relay, available from Schweitzer Engineering, may provide bus protection. In this embodiment, a number of sources may be accommodated and faults may be cleared in 1 millisecond relay operating time. The total clearing time may also include operating time of a breaker. 
     Electric power generation and delivery system  100  may utilize, in various embodiments, a variety of communications protocols and physical communication media. Physical communications medium may include SONET or Ethernet. In one embodiment a fiber optic physical communications media may be used to interconnect the various components of the electric power generation and delivery system  100 . Further, MIRRORED BITS® communications protocol available from Schweitzer Engineering may be used. In alternative embodiments, electric power generation and delivery system  100  may utilize the IEC 61850 protocol and GOOSE messaging, Modbus®, DNP3, and the like. 
     Various embodiments may utilize time-synchronized measurements in connection with various protection schemes. A definition of real-time (synchronized) phasors or synchrophasers is provided in the IEEE Standard 1344-1995. A time signal distributed by the Global Positioning System (GPS) may be used, in various embodiments, as a time source for time-synchronized measure. Thus other sources may also be used. Various signals (i.e., voltage, current, speed, power production, and MVAR) may be recorded from a variety of components in an electrical distribution system. This information is used to design the overall generator protection. The sampling rate of 60 messages per second provides this information every cycle. 
     Synchrophasor measurements may allow for the comparison of data values from a variety of components that may be separated, either geographically or separated components and/or a variety of types of analysis dependent on time. Time synchronization may be used for data organization, real-time decision-making, as well as post-event analysis. The logical comparison of the synchrophasor variables may be performed using a system protection level protection scheme (e.g., system protection block  176  illustrated in  FIG. 1 ). With this functionality, the system performs logic calculations and generates control signals. One or more IEDs included in an electric power generation and delivery system may include various systems for protection, self-monitoring, and event reporting. 
       FIG. 2  illustrates an event report  200  showing voltages and currents in a three-phase electric power generation and delivery system. Event report  200  includes time-synchronized values of each of the three phases of voltage and current. Event report  200  may be displayed to an operator following an event, and/or that may be analyzed following the event.  FIG. 2  illustrates the response of a three-phase electric power generation and delivery system during a period  220  prior to a fault  210  and during a period  230  subsequent to fault  210 . Data from periods  220  and  230  may be preserved so that it may be analyzed in order to understand the root cause of fault  210  and the protection and control operations taken. 
     Other types of reports may also be generated. For example, one embodiment may display voltages, phase angles, and slip frequency of electrical power in an electric power generation and delivery system. In various embodiments, acceptable ranges of these parameters may be specified (e.g., the amount of acceptable slip and phase shift values may be specified by a user). These reports may be displayed graphically in a variety of formats. 
       FIG. 3A  illustrates one system that may implement a protection scheme using synchrophasors for the protection of generators  302 ,  304 ,  306 , and  308 . Generators  302 - 308  are connected to a transmission line  310 . Measurements may be taken at common time, with the phasor at each location at the common time measured and communicated as indicated by the phasor illustrations  312 . 
       FIG. 3B  illustrates a first measured data set  314  and a second measured data set  316  in comparison to a reference data set  318 . In the illustrated example, time-synchronized comparison of the reference data set  318  to the first measured data set  314  shows a difference of 60°. Analysis of these data may be used in a variety of applications, including, modal analysis. Using modal analysis, various embodiments may calculate resonance and oscillation frequencies of an electric power distribution system. In various embodiments, modal analysis may be performed using any of the systems and methods disclosed in U.S. Patent Publication No. 2009/0099798, the entirety of which is incorporated herein by reference. 
     Analysis of synchrophasor data may also be utilized to generate control signals associated with a protection scheme in an electric power generation and delivery system. For example, a protection scheme may comprise rules for load-dependent start/stop, generator running order selection, load shedding, heavy-consumer start block, blackout start and recovery, and/or diesel engine control, based on synchrophasor data. 
       FIG. 4  illustrates a plot of the power output over time of a power generation and distribution system  400 . System  400  includes two generators  410  and  412 . Generators  410  and  412  are connected by a bus  414 . IED  416  is configured to sample the voltage and current on bus  414 . Three periods of time are analyzed based on time-synchronized measurements of power generation. The first time period  420  follows a line trip. System  400  compensates for the line trip and dampens the variations in the power output. The second time period  422  illustrates that system  400  is relatively stable. The damping ratio and amplitude during this period are small, and thus changes in amplitude occur relatively slowly, thus allowing system  400  to control oscillations and to take control actions in order to maintain stability. The third time period  424  follows a line trip and generation drop and precedes a system separation. As illustrated, the damping ratio is negative and the amplitude is large, thus leading to increasing variations in the amplitude of the power output. Analysis of the synchrophasors data may be used to generate a control instruction resulting in the system separation. 
     Using modal analysis, which may be a part of a system level protection scheme, it may be possible to calculate resonance and oscillation frequencies of a system. These calculations may allow for advanced generator protection schemes. For example, analysis of the data corresponding to time period  424  may signal a need to separate generators  410  and  412 . 
     A variety of types of fault detection systems may be included in various embodiments disclosed herein. Various embodiments, for example, may include arc-flash detection systems. In one embodiment, and arc-flash detection system may detect faults in 2 to 3 milliseconds. Such a response time may be effective in limiting any damage caused by an arc-flash. Various embodiments may include relay logic that relies on both light and current to detect a fault. Peak detector logic is enabled to quickly determine the current without losing accuracy, because filtering requirements delay the sensing of current. Various embodiments of arc-flash detection systems and methods are disclosed in co-pending application Ser. No. 12/562,787, titled Secure Arc Flash Detection, the entirety of which is incorporated herein by reference. 
     As discussed above, a system level protection scheme may be configured to detect, prevent, or remedy common-mode faults.  FIGS. 5A and 5B  illustrate one example of a common mode fault. In the example provided in  FIGS. 5A and 5B , a plurality of electrical generators (not shown) may be configured to operate in parallel droop mode. In case of a fault on one generator exciter/governor, a system level protection system may attempt to properly detect and isolate only the faulty generator. In detecting the faulty generator, the system may evaluate the response time of controls (e.g., exciter/governor controls) before making isolating or islanding any of the plurality of generators. 
     When droop and no-load speed are the same on engines driving electrical generators, the generators will share the load equally. Consistent droop results in a predictable speed for a given load on a generator based on a droop curve, the health of the connected engine, and the speed control system. A deviation from this curve beyond an acceptable range is indicative of an unhealthy status in the engine (e.g., the engine is unable to deliver the required power), or a problem with the speed control system or its control system tuning parameters. These symptoms may occur if there is a loss of engine power or a variety of other problems (e.g., a sticky injector, fuel pump failure, dirty fuel filter, incorrectly set ballhead governor, or limited fuel rack linkage movement). 
       FIGS. 5A and 5B  show one example of a common-mode fault that may be detected by a system-level protection scheme.  FIGS. 5A and 5B  show the operation of a system including at least two generators (not shown) operating in parallel, and in which one of the generators is experiencing a governor fault.  FIG. 5A  shows the slope and three percent droop characteristics for the generators operating in parallel. The line designated with reference no.  510  may be selected if the generators are operating around 100 percent of a maximum load. As illustrated, at 100% of load the frequency is equal to 60 Hz. The line designated with reference no.  520  is selected if the generators are operating around 50% of a maximum load. As is also shown, at 50% of maximum load, the frequency is equal to 60 Hz. 
     The system may include a range of acceptable operating conditions  530 . The point labeled point X is within the acceptable range of operation  530 . Point Y is on the boundary of acceptable operating conditions for the common mode faults. In contrast, point Z is outside of acceptable operating conditions, thus indicating the existence of the problem affecting the overall operation the system. If the load is increased beyond 50 percent, the generator experiencing a governor fault bears a greater proportion of the load, but the system operating frequency goes down on the 3 percent slope. The operating frequency will be 59.1 Hz on line  520  if the load is increased to 100 percent of maximum. 
     For a low kW fault, when a plurality of generators are generating at full capacity and one generator is operating at a reduced capacity caused by a fault, the system operating point moves from X to Y, as shown in  FIG. 5B . Point Y remains within the acceptable range of operation; however, the system is operating under less than optimal conditions. If a malfunction causes the system to operate outside of the range of acceptable operating conditions  530 , a protection system may isolate the faulty generator. Accordingly, with the faulty generator isolated, the system load will be shared by the remaining generators. Removal of the faulty generator may cause the system frequency to drop, and may further cause the protection system to generate another control signal to correct the system frequency. 
     A high kW fault may result from speed control feedback loss or actuator signal loss for a particular defective generator. This type of event results in producing more power than scheduled from the defective generator. This type of fault results in the remaining generators running lightly loaded.  FIG. 5B  illustrates that if the operating conditions for a generator change from X to Y, a control instruction may be generated to maintain the system within the range of acceptable operating conditions  530 . If the control instruction does not address the issue, and the system drifts further to point Z, a control instruction may be generated to isolate the defective generator. 
     In addition to the system-level protection system, a generator-level protection system may also be running in droop mode. When droop and no-load voltages are set the same on all generators in a system, the generators share the kVAR equally; however, voltage control may be more complex because of the dependence on exciter controls. Exciter control can be initiated based on system-level conditions, thus allowing a system-level protection system to monitor operating conditions. 
     A variety of problems may be protected against by both a system-level protection system and a generator-level protection system. For example, “generator hunting” may be addressed by both system-level protection and generator-level protection systems. System-level protection may address hunting attributable to faulty AVR electronics, low settings, or unstable voltage control. When a parallel generator is hunting, it periodically takes or sheds reactive power, resulting in hunting in the overall system. System-level protection may identify and take corrective action to isolate a generator causing system hunting, which may, for example, be caused by a faulty exciter. Appropriate action may be programmed based on various parameters and acceptable operating conditions. 
     Some generator faults may be the result of the fuel rack position and actuator current. When actuator current does not track the rack position, an alarm may be generated. In the case of a generator fuel problem (e.g., damage to fuel line or fuel quality), generator output may not follow the generator fuel rack. Appropriate alarms may be generated and the generator with the fuel problem may be isolated. In a typical operation, generator faults resulting from the fuel rack position and actuator current may be detected, and appropriate action may be implemented, by a system protection block. In the event of a communication failure between the system protection block and a local protection block, the local protection block may provide protection against this type of fault for the local generator. 
     Fuel rack hunting may be caused by a number of problems, including dead bands in linkages, faulty speed governor electronics, faulty engine generator shaft coupling, etc. A system-level protection system may analyze operating conditions and generate an alarm for the appropriate generator. An appropriate algorithm may utilize as inputs various generator parameters, including the fuel rack position for each generator, in order to identify fuel rack hunting. Fuel rack hunting may be identified, and appropriate action may be implemented, by a system protection block. In the event of a communication failure between the system protection block and the local protection block, the local protection block may provide protection against this type of fault for the local generator. 
       FIG. 6  illustrates a flow diagram of a method  600  for providing a plurality of local protection blocks  610 A and  610 B and a system protection block  614 . Local protection block  610 A and local protection block  610 B may provide similar functionality, however each local protection block may be configured to monitor a different piece of monitored equipment or segment of an electrical power distribution system. Although  FIG. 6  illustrates only two local protection blocks, any number of protection blocks may be included in order to monitor a particular system. 
     At  620 A and  620 B, local protection block  610 A and  610 B, respectively, may record a plurality of time-synchronized measurements indicating electrical conditions associated with a respective piece of monitored equipment. At  622 A and  6228 , the recorded data may be analyzed for local-level protection actions. It may be determined at  624 A and  624 B whether local-level protection action is required based on the analyzed measurements. If local-level protection action is required, the local-level protection action may be performed at  626 . As discussed above, local-level protection action may be appropriate in remedying a wide variety of potential faults associated with a particular piece of monitored equipment. 
     System protection block  614  accumulates measurements from local protection blocks  610 A and  610 B at  628 . System protection block  614  may analyze the plurality of time-synchronized measurements from the plurality of local protection blocks at  630 . Based on that analysis, a determination may be made regarding whether system-level protection action is required at  632 . If system-level protection action is required, the appropriate system-level protection action may be performed at  634 . 
       FIG. 7  illustrates a block diagram of an IED  700  configured to implement either a local protection block or a system protection block. One of skill in the art will appreciate that with certain modifications, IED  700  may also serve as an access controller, such as access controller  172  shown in  FIG. 1 . A data bus  742  may link a monitored equipment interface  729 , a time input  740 , a network interface  732 , a sensor component  750 , and a computer-readable storage medium  726  to a processor  724 . Network interface  732  may be configured to communicate with a data network. Time input  740  may be configured to receive a time signal. A time signal received via time input  740  may be utilized in order to generate time-synchronized measurements that are based on the same time reference in various locations in an electrical power distribution system. In certain embodiments, a common time reference may be received via network interface  732 , and accordingly, a separate time input would not be necessary. Such embodiments may employ any time reference (e.g., a time reference distributed via the IEEE 1588 protocol, IRIG, or a GPS time source). Monitored equipment interface  729  may be configured to receive status information from and issue control instructions to a piece of monitored equipment. 
     A computer-readable storage medium  726  may be the repository of various modules configured to perform any of the methods described herein, and more specifically to implement the functionality of a local protection block or a system protection block. A local protection block module  720  may include instructions for analyzing a plurality of measurements indicating electrical conditions associated with a particular piece of monitored equipment and determining appropriate circumstances for performing local-level protection actions. Similarly, a system protection block module  722  may include instructions for analyzing a plurality of measurements from a plurality of local protection blocks and determining appropriate circumstances for performing system-level protection actions. A time-synchronized measurements module  728  may include instructions for recording a plurality of measurements indicating electrical conditions associated with monitored equipment, and for associating the plurality of measurements with a time stamp. The time stamp may indicate the time at which each of the plurality of measurements is made. Time-synchronized measurements module  728  may generate a plurality of time-synchronized measurements by associating each of the plurality of measurements with a time stamp. Data collected by time-synchronized measurements module  728  may be analyzed and stored for use in a variety of ways. For example, the plurality of time-synchronized measurements may be used in post-event analysis. 
     In certain embodiments, IED  700  may include a sensor component  750 . In the illustrated embodiment, sensor component  750  is configured to gather data directly from a conductor (not shown) using a current transformer  702  and/or a voltage transformer  714 . Voltage transformer  714  may be configured to step-down the power system&#39;s voltage (V) to a secondary voltage waveform  712  having a magnitude that can be readily monitored and measured by IED  700 . Similarly, current transformer  702  may be configured to proportionally step-down the power system&#39;s line current (I) to a secondary current waveform  704  having a magnitude that can be readily monitored and measured by IED  700 . Low pass filters  708 ,  716  respectively filter the secondary current waveform  704  and the secondary voltage waveform  712 . An analog-to-digital converter  718  may multiplex, sample and/or digitize the filtered waveforms to form corresponding digitized current and voltage signals. 
     In other embodiments, sensor component  750  may be configured to monitor a wide range of characteristics associated with monitored equipment, including equipment status, temperature, frequency, pressure, density, infrared absorption, radio-frequency information, partial pressures, viscosity, speed, rotational velocity, mass, switch status, valve status, circuit breaker status, tap status, meter readings, and the like. 
     A/D converter  718  may be connected to bus  742 . A/D converter  718  may generate digitized representations of current and voltage signals, which may be analyzed by IED  700 . In various embodiments, the digitized current and voltage signals may be compared against conditions, either to determine when it may be appropriate to initiate a local-level protection action or a system-level protection action. 
     Processor  724  may be configured to process communications received via network interface  732 , time input  740 , sensor component  750 , and monitored equipment interface  729 . Processor  724  may operate using any number of processing rates and architectures. Processor  724  may be configured to perform various algorithms and calculations described herein. Processor  724  may be embodied as a general purpose integrated circuit, an application specific integrated circuit, a field-programmable gate array, and other programmable logic devices. 
     It will be obvious to those having skill in the art that many changes may be made to the details of the above-described embodiments without departing from the underlying principles of the invention. The scope of the present invention should, therefore, be determined only by the following claims.