《电子工程师手册》学习资料（英文版）Energy Management 67.pdf_大学文库

67 Energy management 67.2 Power System Data Acquisition and Control 67.3 Automatic Generation Control Load Frequency Control. Economic Dispatch.Reserve Neil n y 67.5 Energy Management Cegelec ESCA Corporation 67.6 Security Control Anjan Bose 67.7 Operator Training Simulator Energy Control System. Power System Dynami Washington State University Simulation. Instructional System 67.1 Introduction Energy management is the process of monitoring, coordinating, and controlling the generation, transmission and distribution of electrical energy. The physical plant to be managed includes generating plants that produce energy fed through transformers to the high-voltage transmission network(grid), interconnecting generating plants and load centers. Transmission lines terminate at substations that perform switching, voltage transfor mation, measurement, and control. Substations at load centers transform to subtransmission and distribution levels. These lower-voltage circuits typically operate radially, i.e., no normally closed paths between substations through subtransmission or distribution circuits (Underground cable networks in large cities are an exception. Since transmission systems provide negligible energy storage, supply and demand must be balanced by either generation or load. Production is controlled by turbine governors at generating plants, and automatic generation control is performed by control center computers remote from generating plants. Load management, sometimes called demand-side management, extends remote supervision and control to subtransmission and distribution circuits, including control of residential, commercial, and industrial load Events such as lightning strikes, short circuits, equipment failure, or accidents may cause a system fault Protective relays actuate rapid, local control through operation of circuit breakers before operators can respond The goal is to maximize safety, minimize damage, and continue to supply load with the least inconvenience to customers. Data acquisition provides operators and computer control systems with status and measurement information needed to supervise overall operations. Security control analyzes the consequences of faults to establish operating conditions that are both robust and economical. Energy management is performed at control centers(see Fig. 67.1), typically called system control centers, by computer systems called energy management systems(EMS). Data acquisition and remote control is per- formed by computer systems called supervisory control and data acquisition(SCADA) systems. These latter systems may be installed at a variety of sites including system control centers. An EMS typically includes a SCADA"front-end"through which it communicates with generating plants, substations, and other remote Ices. Figure 67. 2 illustrates the applications layer of modern EMS as well as the underlying layers on which it is built: the operating system, a database manager, and a utilities/services laye c 2000 by CRC Press LLC

© 2000 by CRC Press LLC 67 Energy Management 67.1 Introduction 67.2 Power System Data Acquisition and Control 67.3 Automatic Generation Control Load Frequency Control • Economic Dispatch • Reserve Monitoring • Interchange Transaction Scheduling 67.4 Load Management 67.5 Energy Management 67.6 Security Control 67.7 Operator Training Simulator Energy Control System • Power System Dynamic Simulation • Instructional System 67.1 Introduction Energy management is the process of monitoring, coordinating, and controlling the generation, transmission, and distribution of electrical energy. The physical plant to be managed includes generating plants that produce energy fed through transformers to the high-voltage transmission network (grid), interconnecting generating plants and load centers. Transmission lines terminate at substations that perform switching, voltage transformation, measurement, and control. Substations at load centers transform to subtransmission and distribution levels. These lower-voltage circuits typically operate radially, i.e., no normally closed paths between substations through subtransmission or distribution circuits. (Underground cable networks in large cities are an exception.) Since transmission systems provide negligible energy storage, supply and demand must be balanced by either generation or load. Production is controlled by turbine governors at generating plants, and automatic generation control is performed by control center computers remote from generating plants. Load management, sometimes called demand-side management, extends remote supervision and control to subtransmission and distribution circuits, including control of residential, commercial, and industrial loads. Events such as lightning strikes, short circuits, equipment failure, or accidents may cause a system fault. Protective relays actuate rapid, local control through operation of circuit breakers before operators can respond. The goal is to maximize safety, minimize damage, and continue to supply load with the least inconvenience to customers. Data acquisition provides operators and computer control systems with status and measurement information needed to supervise overall operations. Security control analyzes the consequences of faults to establish operating conditions that are both robust and economical. Energy management is performed at control centers (see Fig. 67.1), typically called system control centers, by computer systems called energy management systems (EMS). Data acquisition and remote control is performed by computer systems called supervisory control and data acquisition (SCADA) systems. These latter systems may be installed at a variety of sites including system control centers. An EMS typically includes a SCADA “front-end” through which it communicates with generating plants, substations, and other remote devices. Figure 67.2 illustrates the applications layer of modern EMS as well as the underlying layers on which it is built: the operating system, a database manager, and a utilities/services layer. K. Neil Stanton Stanton Associates Jay C. Giri Cegelec ESCA Corporation Anjan Bose Washington State University

Alarms: Informs operator of unplanned events and undesirable operating conditions. Alarms are sorted by criticality, area of responsibility, and chronology. Acknowledgment may be required. Logging: Logs all operator entry, all alarms, and selected information Load shed: Provides both automatic and operator-initiated tripping of load in response to system emergencies. Trending: Plots measurements on selected time scales Since the master station is critical to power system operations, its functions are generally distributed among several computer systems depending on specific design. A dual computer system configured in primary and standby modes is most common SCADA functions are listed below without stating which computer has specific Manage communication circuit configuration Downline load RTU files Maintain scan tables and Check and correct message errors Convert to engineering units Detect status and measurement changes Monitor abnormal and out-of-limit conditions Log and time-tag sequence of events Respond to operator request Display information Acknowledge alarms Transmit control action to rtus Inhibit unauthorized actions Maintain historical files Log events and prepare reports Perform load shedding 67.3 Automatic Generation Control Automatic generation control (AGC) consists of two major and several minor functions that operate on-line in real time to adjust the generation against load at minimum cost. The major functions are load frequency control and economic dispatch, each of which is described below. The minor functions are reserve monitoring, which assures enough reserve on the system, interchange scheduling, which initiates and completes scheduled inter hanges, and other similar monitoring and recording functions. Load Frequency Control Load frequency control (LFC)has to achieve three primary objectives which are stated below in priority order 1. To maintain frequency at the scheduled value 2. To maintain net power interchanges with neighboring control areas at the scheduled values 3. To maintain power allocation among units at economically desired values The first and second objectives are met by monitoring an error signal, called area control error (ACE), which is a combination of net interchange error and frequency error and represents the power imbalance between c 2000 by CRC Press LLC

© 2000 by CRC Press LLC • Alarms: Informs operator of unplanned events and undesirable operating conditions. Alarms are sorted by criticality, area of responsibility, and chronology. Acknowledgment may be required. • Logging: Logs all operator entry, all alarms, and selected information. • Load shed: Provides both automatic and operator-initiated tripping of load in response to system emergencies. • Trending: Plots measurements on selected time scales. Since the master station is critical to power system operations, its functions are generally distributed among several computer systems depending on specific design. A dual computer system configured in primary and standby modes is most common. SCADA functions are listed below without stating which computer has specific responsibility. • Manage communication circuit configuration • Downline load RTU files • Maintain scan tables and perform polling • Check and correct message errors • Convert to engineering units • Detect status and measurement changes • Monitor abnormal and out-of-limit conditions • Log and time-tag sequence of events • Detect and annunciate alarms • Respond to operator requests to: Display information Enter data Execute control action Acknowledge alarms • Transmit control action to RTUs • Inhibit unauthorized actions • Maintain historical files • Log events and prepare reports • Perform load shedding 67.3 Automatic Generation Control Automatic generation control (AGC) consists of two major and several minor functions that operate on-line in real time to adjust the generation against load at minimum cost. The major functions are load frequency control and economic dispatch, each of which is described below. The minor functions are reserve monitoring, which assures enough reserve on the system, interchange scheduling, which initiates and completes scheduled interchanges, and other similar monitoring and recording functions. Load Frequency Control Load frequency control (LFC) has to achieve three primary objectives which are stated below in priority order: 1. To maintain frequency at the scheduled value 2. To maintain net power interchanges with neighboring control areas at the scheduled values 3. To maintain power allocation among units at economically desired values The first and second objectives are met by monitoring an error signal, called area control error (ACE), which is a combination of net interchange error and frequency error and represents the power imbalance between

tion and load at any instant. This ACE must be filtered or smoothed such that excessive and random ges in ACE are not translated into control action. Since these excessive changes are different for different systems, the filter parameters have to be tuned specifically for each control area. The filtered ACE is then used to obtain the proportional plus integral control signal. This control signal is modified by limiters, deadbands, and gain constants that are tuned to the particular system. This control signal is then divided among the generating units under control by using participation factors to obtain unit cor trol errors These participation factors may be proportional to the inverse of the second derivative of the cost of unit generation so that the units would be loaded according to their costs, thus meeting the third objective. However, cost may not be the only consideration because the different units may have different response rates and it may be necessary to move the faster generators more to obtain an acceptable response. The UCEs are then sent to the various units under control and the generating units monitored to see that the corrections take place. This control action is repeated every 2 to 6s In spite of the integral control, errors in frequency and net interchange do tend to accumulate over time. These time errors and accumulated interchange errors have to be corrected by adjusting the controller settings according to procedures agreed upon by the whole interconnection. These accumulated errors as well as aCe serve as performance measures for LFC. The main philosophy in the design of lFC is that each system should follow its own load very closely during normal operation, while during emergencies each system should contribute according to its relative size in the interconnection without regard to the locality of the emergency. Thus, the most important factor in obtaining good control of a system is its inherent capability of following its own load. This is guaranteed if the system has adequate regulation margin as well as adequate response capability. Systems that have mainly thermal generation often have difficulty in keeping up with the load because of the slow response of the units The design of the controller itself is an important factor, and proper tuning of the controller parameters is needed to obtaingood "control without" excessive"movement of units. Tuning is system-specific, and although system simulations are often used as aids, most of the parameter adjustments are made in the field using Economic Dispatch Since all the generating units that are on-line have different costs of generation, it is necessary to find the generation levels of each of these units that would meet the load at the minimum cost. This has to take into account the fact that the cost of generation in one generator is not proportional to its generation level but is function of it. In addition pendent on the generation Certain other factors have to be considered when obtaining the optimum generation pattern. One is that the generation pattern provide adequate reserve margins. This is often done by constraining the generation level to a lower boundary than the generating capability. a more difficult set of constraints to consider are the ansmission limits. Under certain real-time conditions it is possible that the most economic pattern may not be feasible because of unacceptable line flows or voltage conditions. The present-day economic dispatch(ED) algorithm cannot handle these security constraints. However, alternative methods based on optimal power flows have been suggested but have not yet been used for real-time dispatch. The minimum cost dispatch occurs when the incremental cost of all the generators is equal. The cost functions of the generators are nonlinear and discontinuous. For the equal marginal cost algorithm to work it is necessary for them to be convex. These incremental cost curves are often represented as monotonically increasing iecewise-linear functions. A binary search for the optimal marginal cost is conducted by summing all the generation at a certain marginal cost and comparing it with the total power demand. If the demand is higher, t higher marginal cost is needed, and vice versa. This algorithm produces the ideal setpoints for all the generators for that particular demand, and this calculation is done every few minutes as the demand change The losses in the power system are a function of the generation pattern, and they are taken into account by multiplying the generator incremental costs by the appropriate penalty factors. The penalty factor for each generator is a reflection of the sensitivity of that generator to system losses, and these sensitivities can be obtained from the transmission loss factors(Section 67.6 c 2000 by CRC Press LLC

© 2000 by CRC Press LLC generation and load at any instant. This ACE must be filtered or smoothed such that excessive and random changes in ACE are not translated into control action. Since these excessive changes are different for different systems, the filter parameters have to be tuned specifically for each control area. The filtered ACE is then used to obtain the proportional plus integral control signal. This control signal is modified by limiters, deadbands, and gain constants that are tuned to the particular system. This control signal is then divided among the generating units under control by using participation factors to obtain unit control errors (UCE). These participation factors may be proportional to the inverse of the second derivative of the cost of unit generation so that the units would be loaded according to their costs, thus meeting the third objective. However, cost may not be the only consideration because the different units may have different response rates and it may be necessary to move the faster generators more to obtain an acceptable response. The UCEs are then sent to the various units under control and the generating units monitored to see that the corrections take place. This control action is repeated every 2 to 6 s. In spite of the integral control, errors in frequency and net interchange do tend to accumulate over time. These time errors and accumulated interchange errors have to be corrected by adjusting the controller settings according to procedures agreed upon by the whole interconnection. These accumulated errors as well as ACE serve as performance measures for LFC. The main philosophy in the design of LFC is that each system should follow its own load very closely during normal operation, while during emergencies each system should contribute according to its relative size in the interconnection without regard to the locality of the emergency. Thus, the most important factor in obtaining good control of a system is its inherent capability of following its own load. This is guaranteed if the system has adequate regulation margin as well as adequate response capability. Systems that have mainly thermal generation often have difficulty in keeping up with the load because of the slow response of the units. The design of the controller itself is an important factor, and proper tuning of the controller parameters is needed to obtain “good” control without “excessive” movement of units. Tuning is system-specific, and although system simulations are often used as aids, most of the parameter adjustments are made in the field using heuristic procedures. Economic Dispatch Since all the generating units that are on-line have different costs of generation, it is necessary to find the generation levels of each of these units that would meet the load at the minimum cost. This has to take into account the fact that the cost of generation in one generator is not proportional to its generation level but is a nonlinear function of it. In addition, since the system is geographically spread out, the transmission losses are dependent on the generation pattern and must be considered in obtaining the optimum pattern. Certain other factors have to be considered when obtaining the optimum generation pattern. One is that the generation pattern provide adequate reserve margins. This is often done by constraining the generation level to a lower boundary than the generating capability. A more difficult set of constraints to consider are the transmission limits. Under certain real-time conditions it is possible that the most economic pattern may not be feasible because of unacceptable line flows or voltage conditions. The present-day economic dispatch (ED) algorithm cannot handle these security constraints. However, alternative methods based on optimal power flows have been suggested but have not yet been used for real-time dispatch. The minimum cost dispatch occurs when the incremental cost of all the generators is equal. The cost functions of the generators are nonlinear and discontinuous. For the equal marginal cost algorithm to work it is necessary for them to be convex. These incremental cost curves are often represented as monotonically increasing piecewise-linear functions. A binary search for the optimal marginal cost is conducted by summing all the generation at a certain marginal cost and comparing it with the total power demand. If the demand is higher, a higher marginal cost is needed, and vice versa. This algorithm produces the ideal setpoints for all the generators for that particular demand, and this calculation is done every few minutes as the demand changes. The losses in the power system are a function of the generation pattern, and they are taken into account by multiplying the generator incremental costs by the appropriate penalty factors. The penalty factor for each generator is a reflection of the sensitivity of that generator to system losses, and these sensitivities can be obtained from the transmission loss factors (Section 67.6)

This ED algorithm generally applies to only thermal generation units that have cost characteristics of the type discussed here. The hydro units have to be dispatched with different considerations. Although there is no cost for the water, the amount of water available is limited over a period, and the displacement of fossil fuel previously computed hydro optimization, the water worth can be used to dispatch the hydro unit from a by this water determines its worth. Thus, if the water usage limitation over a period is known, LFC and the ED functions both operate automatically in real time but with vastly different time period Both adjust generation levels, but LFC does it every few seconds to follow the load variation, while ed does it every few minutes to assure minimal cost. Conflicting control action is avoided by coordinating the control errors. If the unit control errors from lfc and ed are in the same direction there is no conflict otherwise a logic is set to either follow load (permissive control) or follow ec (mandatory control). Reserve monitoring Maintaining enough reserve capacity is required in case generation is lost. Explicit formulas are followed to determine the spinning(already synchronized)and ready(10 min)reserves required. The availability can be assured by the operator manually, or, as mentioned previously, the ED can also reduce the upper dispatchable limits of the generators to keep such generation available Interchange Transaction Scheduling The contractual exchange of power between utilities has to be taken into account by the LFC and ED functions. This is done by calculating the net interchange(sum of all the buy and sale agreements)and adding this to the generation needed in both the LFC and ED. Since most interchanges begin and end on the hour, the net interchange is ramped from one level to the new over a 10-or 20-min period straddling the hour. The programs achieve this automatically from the list of scheduled transactions 4 Load management SCADA, with its relatively expensive RTUs installed at distribution substations, can provide status and mea- surements for distribution feeders at the substation. Distribution automation equipment is now available to measure and control at locations dispersed along distribution circuits. This equipment can monitor sectional izing devices(switches, interruptors, fuses), operate switches for circuit reconfiguration, control voltage, read customers'meters, implement time-dependent pricing(on-peak, off-peak rates), and switch customer equip- ment to manage load. This equipment requires significantly increased functionality at distribution control centers Distribution control center functionality varies widely from company to company, and the following list is evolving rapidly. Data acquisition: Acquires data and gives the operator control over specific devices in the field Includes data processing, quality checking, and storage Feeder switch control: Provides remote control of feeder switches Tagging and alarms: Provides features similar to SCADA. Diagrams and maps: Retrieves and displays distribution maps and drawings. Supports device selection from these displays Overlays telemetered and operator-entered data on displays Preparation of switching orders: Provides templates and information to facilitate preparation of instruc ions necessary to disconnect, isolate, reconnect, and reenergize equipment. Switching instructions: Guides operator through execution of previously prepared switching orders. Trouble analysis: Correlates data sources to assess scope of trouble reports and possible dispatch of wor Fault location: Analyzes available information to determine scope and location of fault Service restoration: Determines the combination of remote control actions which will maximize resto- ration of service Assists operator to dispatch work crews c 2000 by CRC Press LLC

© 2000 by CRC Press LLC This ED algorithm generally applies to only thermal generation units that have cost characteristics of the type discussed here. The hydro units have to be dispatched with different considerations. Although there is no cost for the water, the amount of water available is limited over a period, and the displacement of fossil fuel by this water determines its worth. Thus, if the water usage limitation over a period is known, say from a previously computed hydro optimization, the water worth can be used to dispatch the hydro units. LFC and the ED functions both operate automatically in real time but with vastly different time periods. Both adjust generation levels, but LFC does it every few seconds to follow the load variation, while ED does it every few minutes to assure minimal cost. Conflicting control action is avoided by coordinating the control errors. If the unit control errors from LFC and ED are in the same direction, there is no conflict. Otherwise, a logic is set to either follow load (permissive control) or follow economics (mandatory control). Reserve Monitoring Maintaining enough reserve capacity is required in case generation is lost. Explicit formulas are followed to determine the spinning (already synchronized) and ready (10 min) reserves required. The availability can be assured by the operator manually, or, as mentioned previously, the ED can also reduce the upper dispatchable limits of the generators to keep such generation available. Interchange Transaction Scheduling The contractual exchange of power between utilities has to be taken into account by the LFC and ED functions. This is done by calculating the net interchange (sum of all the buy and sale agreements) and adding this to the generation needed in both the LFC and ED. Since most interchanges begin and end on the hour, the net interchange is ramped from one level to the new over a 10- or 20-min period straddling the hour. The programs achieve this automatically from the list of scheduled transactions. 67.4 Load Management SCADA, with its relatively expensive RTUs installed at distribution substations, can provide status and measurements for distribution feeders at the substation. Distribution automation equipment is now available to measure and control at locations dispersed along distribution circuits. This equipment can monitor sectionalizing devices (switches, interruptors, fuses), operate switches for circuit reconfiguration, control voltage, read customers’ meters, implement time-dependent pricing (on-peak, off-peak rates), and switch customer equipment to manage load. This equipment requires significantly increased functionality at distribution control centers. Distribution control center functionality varies widely from company to company, and the following list is evolving rapidly. • Data acquisition: Acquires data and gives the operator control over specific devices in the field. Includes data processing, quality checking, and storage. • Feeder switch control: Provides remote control of feeder switches. • Tagging and alarms: Provides features similar to SCADA. • Diagrams and maps: Retrieves and displays distribution maps and drawings. Supports device selection from these displays. Overlays telemetered and operator-entered data on displays. • Preparation of switching orders: Provides templates and information to facilitate preparation of instructions necessary to disconnect, isolate, reconnect, and reenergize equipment. • Switching instructions: Guides operator through execution of previously prepared switching orders. • Trouble analysis: Correlates data sources to assess scope of trouble reports and possible dispatch of work crews. • Fault location: Analyzes available information to determine scope and location of fault. • Service restoration: Determines the combination of remote control actions which will maximize restoration of service. Assists operator to dispatch work crews

Circuit continuity analysis: Analyzes circuit topology and device status to show electrically connected circuit segments( either energ ed or deenergized Power factor and voltage control: Combines substation and feeder data with predetermined operating parameters to control distribution circuit power factor and voltage levels Electrical circuit analysis: Performs circuit analysis, single-phase or three-phase, balanced or unbalanced. Load management: Controls customer loads directly through appliance switching(e.g, water heaters and indirectly through voltage cor Meter reading: Reads customers' meters for billing, peak demand studies, time of use tariffs. Provides remote connect/disconnect 67.5 Energy Management Generation control and ED minimize the current cost of energy production and transmission within the range f available controls. Energy management is a supervisory layer responsible for economically scheduling pro duction and transmission on a global basis and over time intervals consistent with cost optimization. For example, water stored in reservoirs of hydro plants is a resource that may be more valuable in the future and should, therefore, not be used now even though the cost of hydro energy is currently lower than thermal generation. The global consideration arises from the ability to buy and sell energy through the interconnected power system; it may be more economical to buy than to produce from plants under direct control. energy accounting processes transaction information and energy measurements recorded during actual operation basis of payment for energy sales and purchases Energy management includes the following functions: System load forecast: Forecasts system energy demand each hour for a specified forecast period of 1 to 7 days. Unit commitment: Determines start-up and shut-down times for most economical operation of thermal generating units for each hour of a specified period of 1 to 7 days Fuel scheduling: Determines the most economical choice of fuel consistent with plant requirements, fuel purchase contracts, and stockpiled fuel Hydro-thermal scheduling: Determines the optimum schedule of thermal and hydro energy production for each hour of a study period up to 7 days while ensuring that hydro and thermal constraints are not violated. Transaction evaluation: Determines the optimal incremental and production costs for exchange(pur- chase and sale) of additional blocks of energy with neighboring companies Transmission loss minimization: Recommends controller actions to be taken in order to minimize overall ecurity constrained dispatch: Determines optimal outputs of generating units to minimize production cost while ensuring that a network security constraint is not violated Production cost calculation: Calculates actual and economical production costs for each generating unit on an hourly basis 67.6 Security Control Power systems are designed to survive all probable contingencies. A contingency is defined as an event that causes one or more important components such as transmission lines, generators, and transformers to be unexpectedly removed from service. Survival means the system stabilizes and continues to operate at acceptable voltage and frequency levels without loss of load Operations must deal with a vast number of possible conditions experienced by the system, many of which are not anticipated in planning. Instead of dealing with the impossible task of analyzing all possible system states, security control starts with a specific state: the current state if executing the real-time network sequence; a postulated state if executing a study sequence. Sequence means sequential execution of programs that perform the following steps c 2000 by CRC Press LLC

© 2000 by CRC Press LLC • Circuit continuity analysis: Analyzes circuit topology and device status to show electrically connected circuit segments (either energized or deenergized). • Power factor and voltage control: Combines substation and feeder data with predetermined operating parameters to control distribution circuit power factor and voltage levels. • Electrical circuit analysis: Performs circuit analysis, single-phase or three-phase, balanced or unbalanced. • Load management: Controls customer loads directly through appliance switching (e.g., water heaters) and indirectly through voltage control. • Meter reading: Reads customers’ meters for billing, peak demand studies, time of use tariffs. Provides remote connect/disconnect. 67.5 Energy Management Generation control and ED minimize the current cost of energy production and transmission within the range of available controls. Energy management is a supervisory layer responsible for economically scheduling production and transmission on a global basis and over time intervals consistent with cost optimization. For example, water stored in reservoirs of hydro plants is a resource that may be more valuable in the future and should, therefore, not be used now even though the cost of hydro energy is currently lower than thermal generation. The global consideration arises from the ability to buy and sell energy through the interconnected power system; it may be more economical to buy than to produce from plants under direct control. Energy accounting processes transaction information and energy measurements recorded during actual operation as the basis of payment for energy sales and purchases. Energy management includes the following functions: • System load forecast: Forecasts system energy demand each hour for a specified forecast period of 1 to 7 days. • Unit commitment: Determines start-up and shut-down times for most economical operation of thermal generating units for each hour of a specified period of 1 to 7 days. • Fuel scheduling: Determines the most economical choice of fuel consistent with plant requirements, fuel purchase contracts, and stockpiled fuel. • Hydro-thermal scheduling: Determines the optimum schedule of thermal and hydro energy production for each hour of a study period up to 7 days while ensuring that hydro and thermal constraints are not violated. • Transaction evaluation: Determines the optimal incremental and production costs for exchange (purchase and sale) of additional blocks of energy with neighboring companies. • Transmission loss minimization: Recommends controller actions to be taken in order to minimize overall power system network losses. • Security constrained dispatch: Determines optimal outputs of generating units to minimize production cost while ensuring that a network security constraint is not violated. • Production cost calculation: Calculates actual and economical production costs for each generating unit on an hourly basis. 67.6 Security Control Power systems are designed to survive all probable contingencies. A contingency is defined as an event that causes one or more important components such as transmission lines, generators, and transformers to be unexpectedly removed from service. Survival means the system stabilizes and continues to operate at acceptable voltage and frequency levels without loss of load. Operations must deal with a vast number of possible conditions experienced by the system, many of which are not anticipated in planning. Instead of dealing with the impossible task of analyzing all possible system states, security control starts with a specific state: the current state if executing the real-time network sequence; a postulated state if executing a study sequence. Sequence means sequential execution of programs that perform the following steps:

Real-time Network Analysis sequence ower flo Action Power Optimal Power Flow FIGURE 67 3 Real-time and study network analysis sequences 1. Determine the state of the system based on either current or postulated conditions. 2. Process a list of contingencies to determine the consequences of each contingency on the system in its 3. Determine preventive or corrective action for those contingencies which represent unacceptable risk. eal-time and study network analysis sequences are diagramed in Fig. 67.3 Security control requires topological processing to build network models and uses large-scale ac network typically includes the following functions Topology processor: Processes real-time status measurements to determine an electrical connectivity State estimator: Uses real-time status and analog measurements to determine the "best " estimate of the state of the power system. It uses a redundant set of measurements; calculates voltages, phase angles, and power flows for all components in the system; and reports overload conditions Power flow: Determines the steady-state conditions of the power system network for a specified gener ation and load pattern. Calculates voltages, phase angles, and flows across the entire system Contingency analysis: Assesses the impact of a set of contingencies on the state of the power system and identifies potentially harmful contingencies that cause operating limit violations ptimal power flow: Recommends controller actions to optimize a specified objective function( such as system operating cost or losses) subject to a set of power system operating constraints Security enhancement: Recommends corrective control actions to be taken to alleviate an existing or potential overload in the system while ensuring minimal operational cost. Preventive action: Recommends control actions to be taken in a"preventive "mode before a contingency occurs to preclude an overload situation if the contingency were to occur. Bus load forecasting: Uses real-time measurements to adaptively forecast loads for the electrical connec- ity(bus)model of the power system ne Transmission loss factors: Determines incremental loss sensitivities for generating units; calculates the impact on losses if the output of a unit were to be increased by 1 MW. Short-circuit analysis: Determines fault currents for single-phase and three-phase faults for fault locations across the entire power system network

© 2000 by CRC Press LLC 1. Determine the state of the system based on either current or postulated conditions. 2. Process a list of contingencies to determine the consequences of each contingency on the system in its specified state. 3. Determine preventive or corrective action for those contingencies which represent unacceptable risk. Real-time and study network analysis sequences are diagramed in Fig. 67.3. Security control requires topological processing to build network models and uses large-scale ac network analysis to determine system conditions. The required applications are grouped as a network subsystem which typically includes the following functions: • Topology processor: Processes real-time status measurements to determine an electrical connectivity (bus) model of the power system network. • State estimator: Uses real-time status and analog measurements to determine the ‘‘best’’ estimate of the state of the power system. It uses a redundant set of measurements; calculates voltages, phase angles, and power flows for all components in the system; and reports overload conditions. • Power flow: Determines the steady-state conditions of the power system network for a specified generation and load pattern. Calculates voltages, phase angles, and flows across the entire system. • Contingency analysis: Assesses the impact of a set of contingencies on the state of the power system and identifies potentially harmful contingencies that cause operating limit violations. • Optimal power flow: Recommends controller actions to optimize a specified objective function (such as system operating cost or losses) subject to a set of power system operating constraints. • Security enhancement: Recommends corrective control actions to be taken to alleviate an existing or potential overload in the system while ensuring minimal operational cost. • Preventive action: Recommends control actions to be taken in a “preventive” mode before a contingency occurs to preclude an overload situation if the contingency were to occur. • Bus load forecasting: Uses real-time measurements to adaptively forecast loads for the electrical connectivity (bus) model of the power system network. • Transmission loss factors: Determines incremental loss sensitivities for generating units; calculates the impact on losses if the output of a unit were to be increased by 1 MW. • Short-circuit analysis: Determines fault currents for single-phase and three-phase faults for fault locations across the entire power system network. FIGURE 67.3 Real-time and study network analysis sequences

Relays are modeled, and they emulate the behavior of the actual devices in the fiel ated at periodic intervals. flows and states(bus voltages and angles, topology, transformer taps, etc. )are calcula Instructional System This subsystem includes the capabilities to start, stop, restart, and control the simulation. It also includes making savecases, retrieving savecases, reinitializing to a new time, and initializing to a specific real-time situation. is also used to define event schedules. Events are associated with both the power system simulation and the ECS functions. Events may be deterministic(occur at a predefined time), conditional(based on a predefined set of power system conditions being met), or probabilistic(occur at random Defining Terms Application: A software function within the energy management system which allows the operator to perform a specific set of tasks to meet a specific set of objectives Dispatch: The allocation of generation requirement to the various generating units that are available Distribution system: That part of the power system network which is connected to, and responsible for, the final delivery of power to the customer; typically the part of the network that operates at 33 kv and below to 120 V. Interchange or transaction: A negotiated purchase or sale of power between two companies. Remote terminal unit(RTU): Hardware that gathers system-wide real-time data from various locations within substations and generating plants for telemetry to the energ management syst Security: The ability of the power system to sustain and survive planned and unplanned events without violating operational constraints Related Topics 65.3 Secondary Distribution System.65.6 Load Characteristics.66.1 Generators. 105 1 Introduction References Application of Optimization Methods for Economy/Security Functions in Power System Operations, IEEE tutorial course, IEEE Publication 90EH0328-5-PWR, 1990 Distribution Automation, IEEE Power Engineering Society, IEEE Publication EH0280-8-PBM, 1988 C. J. Erickson, Handbook of Electrical Heating, IEEE Press, 1995 Energy Control Center Design, IEEE tutorial course, IEEE Publication 77 TU0010-9 PWR, 1977. Fundamentals of Load Management, IEEE Power Engineering Society, IEEE Publication EHO289-9-PBM, 1988 Fundamentals of Supervisory Controls, IEEE tutorial course, IEEE Publication 91 EH0337-6 PWR,1991 M. Kleinpeter, Energy Planning and Policy, New York: Wiley, 1995 Special issue on computers in power system operations, Proc. IEEE, voL. 75, no. 12, 1987. W C. Turner, Energy Management Handbook, Fairmont Press, 1997. Further information Current innovations and applications of new technologies and algorithms are presented in the following publication IEEE Power Engineering Review(monthly) IEEE Transactions on Power Systems(bimonthly) Proceedings of the Power Industry Computer Application Conference(biannual) c 2000 by CRC Press LLC

© 2000 by CRC Press LLC flows and states (bus voltages and angles, topology, transformer taps, etc.) are calculated at periodic intervals. Relays are modeled, and they emulate the behavior of the actual devices in the field. Instructional System This subsystem includes the capabilities to start, stop, restart, and control the simulation. It also includes making savecases, retrieving savecases, reinitializing to a new time, and initializing to a specific real-time situation. It is also used to define event schedules. Events are associated with both the power system simulation and the ECS functions. Events may be deterministic (occur at a predefined time), conditional (based on a predefined set of power system conditions being met), or probabilistic (occur at random). Defining Terms Application: A software function within the energy management system which allows the operator to perform a specific set of tasks to meet a specific set of objectives. Dispatch: The allocation of generation requirement to the various generating units that are available. Distribution system: That part of the power system network which is connected to, and responsible for, the final delivery of power to the customer; typically the part of the network that operates at 33 kV and below, to 120 V. Interchange or transaction: A negotiated purchase or sale of power between two companies. Remote terminal unit (RTU): Hardware that gathers system-wide real-time data from various locations within substations and generating plants for telemetry to the energy management system. Security: The ability of the power system to sustain and survive planned and unplanned events without violating operational constraints. Related Topics 65.3 Secondary Distribution System • 65.6 Load Characteristics • 66.1 Generators • 105.1 Introduction References Application of Optimization Methods for Economy/Security Functions in Power System Operations, IEEE tutorial course, IEEE Publication 90EH0328-5-PWR, 1990. Distribution Automation, IEEE Power Engineering Society, IEEE Publication EH0280-8-PBM, 1988. C. J. Erickson, Handbook of Electrical Heating, IEEE Press, 1995. Energy Control Center Design, IEEE tutorial course, IEEE Publication 77 TU0010-9 PWR, 1977. Fundamentals of Load Management, IEEE Power Engineering Society, IEEE Publication EH0289-9-PBM, 1988. Fundamentals of Supervisory Controls, IEEE tutorial course, IEEE Publication 91 EH0337-6 PWR, 1991. M. Kleinpeter, Energy Planning and Policy, New York: Wiley, 1995. “Special issue on computers in power system operations,” Proc. IEEE, vol. 75, no. 12, 1987. W. C. Turner, Energy Management Handbook, Fairmont Press, 1997. Further Information Current innovations and applications of new technologies and algorithms are presented in the following publications: • IEEE Power Engineering Review (monthly) • IEEE Transactions on Power Systems (bimonthly) • Proceedings of the Power Industry Computer Application Conference (biannual)