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Automatic generation control
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In an electric power system, automatic generation control (AGC) is a system for adjusting the power output of multiple generators at different power plants, in response to changes in the load. Since a power grid requires that generation and load closely balance moment by moment, frequent adjustments to the output of generators are necessary. The balance can be judged by measuring the system frequency; if it is increasing, more power is being generated than used, which causes all the machines in the system to accelerate. If the system frequency is decreasing, more load is on the system than the instantaneous generation can provide, which causes all generators to slow down.
History
[edit]Before the use of automatic generation control, one generating unit in a system would be designated as the regulating unit and would be manually adjusted to control the balance between generation and load to maintain system frequency at the desired value. The remaining units would be controlled with speed droop to share the load in proportion to their ratings. With automatic systems, many units in a system can participate in regulation, reducing wear on a single unit's controls and improving overall system efficiency, stability, and economy.
Where the grid has tie interconnections to adjacent control areas, automatic generation control helps maintain the power interchanges over the tie lines at the scheduled levels. With computer-based control systems and multiple inputs, an automatic generation control system can take into account such matters as the most economical units to adjust, the coordination of thermal, hydroelectric, and other generation types, and even constraints related to the stability of the system and capacity of interconnections to other power grids.[1]
Types
[edit]Turbine-governor control
[edit]Turbine generators in a power system have stored kinetic energy due to their large rotating masses. All the kinetic energy stored in a power system in such rotating masses is a part of the grid inertia. When system load increases, grid inertia is initially used to supply the load. This, however, leads to a decrease in the stored kinetic energy of the turbine generators. Since the mechanical power of these turbines correlates with the delivered electrical power, the turbine generators have a decrease in angular velocity, which is directly proportional to a decrease in frequency in synchronous generators.
The purpose of the turbine-governor control (TGC) is to maintain the desired system frequency by adjusting the mechanical power output of the turbine.[2] These controllers have become automated and at steady state, the frequency-power relation for turbine-governor control is,
where,
is the change in turbine mechanical power output
is the change in a reference power setting
is the regulation constant which quantifies the sensitivity of the generator to a change in frequency
is the change in frequency.
For steam turbines, steam turbine governing adjusts the mechanical output of the turbine by increasing or decreasing the amount of steam entering the turbine via a throttle valve.
Load-frequency control
[edit]Load-frequency control (LFC) is employed to allow an area to first meet its own load demands, then to assist in returning the steady-state frequency of the system, Δf, to zero.[3] Load-frequency control operates with a response time of a few seconds to keep system frequency stable.
Economic dispatch
[edit]The goal of economic dispatch is to minimize total operating costs in an area by determining how the real power output of each generating unit will meet a given load.[4] Generating units have different costs to produce a unit of electrical energy, and incur different costs for the losses in transmitting energy to the load. An economic dispatch algorithm will run every few minutes to select the combination of generating unit power setpoints that minimizes overall cost, subject to the constraints of transmission limitation or security of the system against failures.[5] Further constraints may be imposed by the water supply of hydroelectric generation, or by the availability of sun and wind power.
See also
[edit]References
[edit]- ^ Robert Herschel Miller, James H. Malinowski, Power system operation, McGraw-Hill Professional, 1994 ISBN 0-07-041977-9, page 86-87
- ^ Glover, Duncan J. et al. Power System Analysis and Design. 5th Edition. Cengage Learning. 2012. pp. 657-658.
- ^ Glover, Duncan J. et al. Power System Analysis and Design. 5th Edition. Cengage Learning. 2012. pp. 663.
- ^ Glover, Duncan J. et al. Power System Analysis and Design. 5th Edition. Cengage Learning. 2012. pp. 667.
- ^ Richard C. Dorf (ed.), Section 9.3 "Automatic Generation Control" in Electrical Engineering Handbook Taylor and Francis, 2006 ISBN 978-0-8493-2274-7
Automatic generation control
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Introduction
Definition and Purpose
Automatic generation control (AGC) is a centralized feedback control system in electric power grids that automatically adjusts the active power output of multiple generators within a control area to balance generation and load demand in real time. This system operates by monitoring frequency deviations and tie-line power flows, issuing set-point changes to generators to restore balance without requiring operator intervention. AGC ensures that the total generation matches the total load plus losses, maintaining system integrity across interconnected grids. The primary purposes of AGC include frequency regulation, which keeps the system frequency close to its nominal value (typically 50 or 60 Hz) by counteracting imbalances caused by fluctuating loads or generator outages; tie-line power control, which preserves scheduled power exchanges between interconnected control areas to support reliability and commerce; and facilitating economic operation by optimizing generator dispatch within predefined constraints. These objectives collectively enable a stable and efficient power supply, minimizing deviations that could lead to cascading failures. Regulating reserve, a key component, refers to the portion of generation capacity held in readiness and responsive to AGC signals, typically ramping up or down within seconds to minutes to absorb disturbances. Generation-load balance, the core principle, ensures that instantaneous power supply equals demand to prevent frequency drift or blackouts. In contrast to earlier manual methods where operators individually adjusted generator outputs based on meter readings, AGC provides automated, coordinated control across multiple units, reducing response times and human error while handling the complexities of modern interconnected systems. This centralized approach underpins the reliability of bulk power operations, though it relies on communication infrastructure and predefined control strategies for effectiveness.Role in Power System Stability
Automatic Generation Control (AGC) serves as the secondary control layer that restores system frequency to its nominal value following initial disturbances, such as sudden load changes or generator outages, after primary governor response has stabilized the deviation. In North America, the nominal frequency is 60 Hz, whereas in Europe, Asia, and most other regions, it is 50 Hz. This restoration process typically occurs within minutes, ensuring long-term frequency regulation and preventing prolonged imbalances that could compromise system integrity.[5][6][5] In interconnected power grids comprising multiple balancing authority areas, AGC is vital for regulating tie-line power flows to their scheduled values, thereby maintaining equitable power exchanges and averting overloads that might propagate into cascading failures. By continuously monitoring and minimizing the Area Control Error—which integrates frequency deviation with unscheduled tie-line flows—AGC fosters coordinated operation across areas, enhancing the overall resilience of the bulk power system.[5][5] Inadequate AGC performance can lead to persistent frequency deviations beyond narrow operational limits (e.g., approximately 0.018 Hz RMS in the Eastern Interconnection under NERC CPS1), which could escalate to thresholds triggering protective measures like under-frequency load shedding (typically around 59.5 Hz in North America) or, in severe cases, widespread blackouts to safeguard equipment and prevent further instability.[5][7] To enable its responsive actions, AGC draws upon allocated spinning reserves for immediate adjustments and non-spinning reserves for supplementary support during larger disturbances, ensuring adequate capacity is available without compromising reliability.[5] Effective AGC deployment yields significant benefits, including improved grid efficiency through optimized real-time generation adjustments that minimize energy losses, reduced mechanical stress and wear on turbines and generators via gradual rather than abrupt control signals, and enhanced support for dynamic operations in response to variable loads.[5][5]Historical Development
Early Manual Control (Pre-1960s)
In the early 20th century, electric power generation occurred primarily in isolated plants, where basic mechanical governors provided the initial means of frequency regulation. These devices, often centrifugal governors attached to steam or hydraulic turbines, automatically adjusted valve positions to control fuel or water flow in response to speed deviations, helping maintain a rough balance between generation and local load. However, without centralized coordination, operators relied on manual set-point adjustments via handwheels or levers to fine-tune output, limiting the systems to small-scale, independent operations that could not efficiently handle varying demands or disturbances.[8] As power systems expanded into interconnected networks during the mid-20th century, the pre-automatic generation control (AGC) era emphasized manual methods to achieve system-wide balance. Operators typically designated one generating unit as the "regulating unit," whose output was manually adjusted by control room personnel to counteract frequency deviations and load fluctuations across the network. Coordination between plants and control centers occurred via telephone lines and leased communication circuits, allowing dispatchers to issue instructions for raising or lowering generation based on real-time reports of load changes and tie-line flows. This approach, while effective for modest interconnections, depended heavily on human judgment and communication reliability.[9] Despite these practices, manual control exhibited significant limitations, particularly as grids grew larger and more complex following World War II electrification efforts. Response times to sudden load variations were inherently slow, often taking minutes or longer due to the need for operator assessment and manual implementation, which could exacerbate frequency excursions. Human error posed additional risks, such as miscalculations in adjusting the regulating unit amid incomplete information from remote sites. Moreover, scaling to extensive interconnections strained these methods, as nonlinear load behaviors and distant coordination challenges led to steady-state frequency errors and reduced precision in power sharing.[10] By the 1950s, manual control had become the established standard in U.S. and European power systems, with operators continuing to rely on designated regulating units for frequency and interchange management. However, it increasingly revealed inadequacies for handling the demands of large-scale interconnections, including stability concerns in regions like the U.S. Northeast, where post-war grid expansions created precursor issues to major disruptions by amplifying vulnerabilities in manual oversight and response. Nathan Cohn's 1950 work on power flow control in interconnected systems highlighted these gaps, advocating for improved coordination to mitigate risks in expanding networks.[10][9]Emergence of Automated Systems
The transition to automated generation control systems accelerated in the 1960s as power grids expanded and interconnected, necessitating real-time responses beyond manual capabilities. The 1965 Northeast Blackout, which disrupted service to over 30 million people across eight U.S. states and parts of Ontario by cascading from a transmission line fault, underscored the urgency for advanced control technologies. This event prompted the establishment of the North American Electric Reliability Council (NERC) in 1968 to coordinate reliability practices among utilities, including the promotion of automated controls to prevent frequency deviations and tie-line errors.[11] By the late 1960s, digital computers began replacing analog systems for automatic generation control (AGC) in the United States, enabling precise real-time adjustments to generator outputs based on load changes and frequency signals. These early implementations integrated AGC into energy management systems (EMS) for coordinated operation across utilities, marking the first widespread deployment of computer-based AGC to maintain system balance. In the 1970s, key milestones included the IEEE Std 94-1968, which standardized terminology for AGC on electric power systems, facilitating consistent design and operation of control algorithms. Adoption in interconnected pools, such as pilots in the PJM Interconnection during the 1960s, demonstrated AGC's role in managing multi-utility generation for improved reliability and efficiency.[9][1] Regulatory influences grew through NERC's operating guides in the 1980s, which emphasized AGC implementation for frequency regulation and interchange scheduling to enhance North American grid reliability, though enforcement remained voluntary until later legislation. Technological enablers like supervisory control and data acquisition (SCADA) systems, evolving from early 20th-century telemetry to digital platforms in the 1960s–1970s, provided the remote monitoring and control signals essential for AGC, allowing operators to dispatch commands to generators over vast areas. By the 1990s, AGC evolved to support multi-area coordination, where control areas shared data for seamless tie-line management across regions.[9]Control Hierarchy
Primary Control: Governor Response
Primary control serves as the immediate, decentralized response to frequency deviations in power systems, acting as the first line of defense against load-generation imbalances through automatic speed regulation provided by governors on synchronous generators. These governors detect changes in rotational speed—indicative of frequency variations—and adjust the mechanical power input to the turbine accordingly, thereby stabilizing the system frequency on a local basis without requiring central coordination. This mechanism ensures that synchronous machines collectively contribute to arresting frequency excursions within seconds, preventing widespread instability.[12] Turbine-governor systems vary by prime mover type but share the core function of responding to speed deviations. In steam turbines, governors control steam valves to modulate flow based on speed sensors, often using proportional-integral (PI) or proportional control with rate limits on valve motion and reheater dynamics. Hydroelectric governors manage water flow through penstock and wicket gates, incorporating nonlinear gain adjustments and water column time constants for response. Gas turbine governors employ PID control on fuel flow, accounting for acceleration limits and ambient conditions. Traditional flyball mechanisms, which mechanically sense speed via centrifugal force, have largely been supplanted by electronic governors for precise, faster actuation across these types.[12][13][14] The droop characteristic defines the primary control's proportional behavior, where generator output increases inversely with frequency drops to share load proportionally among units. Typically set at 4-5% droop, this means a 4% reduction in frequency from nominal (e.g., 60 Hz to 57.6 Hz) prompts a full rated power increase, establishing a linear speed-power relationship that ensures stable parallel operation. This setting balances responsiveness with system-wide stability, as higher droop values (e.g., 5-10%) reduce sensitivity but enhance damping.[13][14][12] Activation occurs on a seconds-scale, with initial valve or gate movements in 0.1-1 seconds for gas and hydro units, extending to 10 seconds for steam due to thermal dynamics, providing temporary power balance until secondary control intervenes. Governors often include a deadband—typically ±0.036 Hz—to filter minor fluctuations and avoid unnecessary wear, which can delay response to small deviations.[12][13][15] In steady-state operation relying solely on primary control, a persistent frequency error remains due to the proportional droop nature, such as a 1.2 Hz offset at half load for a 4% droop setting, necessitating higher-level controls for restoration to nominal frequency.[12][13]Secondary Control: Automatic Generation Control
Automatic Generation Control (AGC) serves as the centralized secondary control mechanism in power systems, supervising multiple generators through control centers to restore system frequency and tie-line power flows to their nominal values following disturbances. Unlike local primary control, AGC operates on a system-wide basis via the Balancing Authority's Energy Management System (EMS), utilizing integral control to eliminate steady-state frequency errors and ensure precise energy balance on a minute-to-minute timescale.[16] The AGC process begins with continuous monitoring of system frequency, actual generator outputs, and tie-line flows using Supervisory Control and Data Acquisition (SCADA) systems, which poll data every 2–6 seconds. Based on this information, AGC computes the Area Control Error (ACE), representing the deviation between actual and scheduled net interchange plus a frequency bias term, and generates adjustment signals—such as power pulses or set-point changes—to dispatch to participating generating units, thereby counteracting imbalances and restoring nominal conditions.[16] This dispatch targets resources with sufficient headroom, typically regulating a subset of total generation capacity to maintain stability without overcommitting units. In multi-area operations, AGC coordinates across interconnected Balancing Authority areas through tie-line metering and oversight by Reliability Coordinators, ensuring that scheduled interchanges are preserved while each area handles its local imbalances to avoid unintended power flows. AGC typically employs proportional-integral (PI) controllers to achieve this coordination, where the proportional term provides rapid response to transient errors and the integral term ensures zero steady-state deviation in frequency and tie-line power.[16][17] With a response timeframe of 1–10 minutes, AGC follows the faster primary control actions, allowing time for primary responses to stabilize initial transients before finer adjustments are made to fully restore the system. This layered approach ensures reliable operation, with AGC regulating approximately 1–5% of total generation capacity in typical setups to provide the necessary flexibility for secondary regulation.[16][18]Tertiary Control: Economic Dispatch
Tertiary control operates as a supervisory layer in the power system control hierarchy, typically implemented through manual or semi-automated processes to adjust automatic generation control (AGC) set-points for economic efficiency over time horizons ranging from 15 to 60 minutes. This level of control focuses on optimizing the overall operation of generating units after secondary control has restored frequency balance, ensuring that generation resources are allocated to minimize operational costs while maintaining system reliability. Unlike the real-time responsiveness of secondary control, tertiary actions allow operators to refine schedules based on updated forecasts of load and generation availability.[19][20] Economic dispatch forms the core of tertiary control, involving the allocation of total load among available generating units to minimize fuel and production costs subject to power balance and operational limits. Traditional methods include the merit order approach, which ranks generators by their incremental heat rates or marginal costs and dispatches them in ascending order of cost until demand is met, providing a simple heuristic for non-convex cost functions. For more precise solutions, the lambda-iteration technique iteratively solves for the system lambda (equal to the marginal cost at optimum) by adjusting generator outputs until the condition that incremental costs equal lambda is satisfied across units, enabling efficient dispatch even with quadratic cost curves. These principles ensure that lower-cost units are prioritized, reducing overall system expenses without compromising supply adequacy.[21][22] Tertiary control integrates with AGC by supplying base points—the targeted power outputs for each generator—and participation factors that dictate how AGC adjustments are proportionally distributed among units to maintain economic optimality during secondary regulation. These parameters, derived from the latest economic dispatch solution, guide AGC to steer the system toward a cost-minimizing operating point while responding to frequency deviations, effectively bridging short-term balancing with longer-term efficiency. For instance, participation factors are often computed as the ratio of a unit's economic sensitivity to total system sensitivity, ensuring that load changes are shared in proportion to marginal costs.[23][24] Key constraints in tertiary control include generator minimum and maximum output limits, ramp rates that restrict how quickly units can change power levels, and reserve requirements to ensure sufficient contingency margins for unexpected events. These bounds are incorporated into the dispatch optimization to prevent infeasible schedules, with ramp rates particularly influencing the feasibility of set-point adjustments over the 15-60 minute horizon. Unit commitment serves as a precursor to economic dispatch within this context, determining the on/off status and start-up/shutdown schedules of generators over a planning period (typically hours to a day) to provide the set of available units for subsequent dispatch, thereby optimizing both commitment costs and dispatch efficiency in AGC-supported operations.[20][25]Mathematical Modeling
Swing Equation and Frequency Dynamics
The swing equation describes the fundamental dynamics of synchronous generator rotor motion in power systems, derived from Newton's second law applied to the rotating masses of the turbine-generator set.[26] For rotational systems, this law states that the net torque $ T_a $ equals the moment of inertia $ J $ times the angular acceleration $ \frac{d^2 \theta}{dt^2} $, or $ J \frac{d^2 \theta}{dt^2} = T_a $, where $ T_a = T_m - T_e $ with $ T_m $ as mechanical torque and $ T_e $ as electromagnetic torque.[26] Converting torques to power terms via $ P = T \omega $ (with $ \omega $ as angular speed) and normalizing to per-unit values on a machine base yields the swing equation in its standard form for frequency dynamics:
where $ H $ is the inertia constant (in seconds), $ f_0 $ is the nominal frequency (typically 50 or 60 Hz), $ \frac{df}{dt} $ is the rate of change of frequency, $ P_m $ is the mechanical power input from the prime mover (in per unit), $ P_e $ is the electrical power output, $ D $ is the damping coefficient (in per unit), and $ \Delta f = f - f_0 $ is the frequency deviation.[26] This equation captures the balance between accelerating power (from imbalances in $ P_m $ and $ P_e $) and the inertial response that resists changes in rotor speed, thereby linking mechanical and electrical domains.[27]
In the single-machine infinite-bus (SMIB) model, the swing equation is simplified for frequency analysis by assuming the infinite bus provides a constant voltage and frequency reference, isolating the dynamics of one generator connected through a transmission line with reactance $ X $.[28] Here, $ P_e $ is expressed as $ P_e = \frac{E V}{X} \sin \delta $, where $ E $ and $ V $ are the internal and bus voltages, and $ \delta $ is the rotor angle, but for small frequency deviations, linear approximations focus on the inertial and damping terms to study local frequency response without multi-machine interactions.[26]
The inertia constant $ H $ quantifies the stored kinetic energy in the rotating mass relative to the machine's rated power, directly influencing the rate of change of frequency (RoCoF), $ \frac{df}{dt} $, which measures how quickly frequency deviates following a power imbalance. Higher $ H $ values provide greater resistance to frequency changes, stabilizing the system during primary control actions where governors respond to initial disturbances. Typical $ H $ values range from 2 to 10 seconds for thermal and hydro units, with hydro generators often at 2-4 seconds and thermal units (e.g., steam or gas) at 3-7 seconds depending on turbine type and size.[29]
Area Control Error (ACE)
The Area Control Error (ACE) serves as the primary performance metric in automatic generation control (AGC), quantifying the deviation between scheduled and actual power interchange while incorporating frequency imbalances to guide corrective actions. It is defined as the algebraic sum of the tie-line power deviation and a frequency-biased term, expressed mathematically as:
where represents the deviation in tie-line power flow (in MW), is the frequency bias setting (in MW/Hz), and is the deviation in system frequency from its scheduled value (in Hz).[24] This formulation ensures that ACE captures both local interchange errors and contributions to overall interconnection frequency regulation.[5]
The derivation of the ACE equation integrates the need to address two key errors in interconnected power systems: the interchange error (), which measures unscheduled power flows across tie lines, and the frequency error (), which reflects system-wide imbalances. By scaling the frequency error with the bias , the equation combines these into a single, dimensionally consistent signal suitable for proportional-integral (PI) control in AGC, allowing areas to respond proportionally to their size and characteristics while supporting collective frequency restoration.[24] This approach prevents isolated frequency corrections from ignoring scheduled inter-area transfers, promoting coordinated secondary control across multiple balancing authorities.[5]
The frequency bias is calculated as the sum of the area's load damping characteristic (in MW/Hz), which accounts for inherent load-frequency sensitivity, and the reciprocal of the equivalent governor droop (in pu), representing the aggregate turbine-governor response: .[24] In practice, is estimated from historical load-frequency data, while aggregates the inverse droop settings of participating generators, typically around 5% per unit in North American systems.[24] Standards require to be set annually at 100-125% of the measured frequency response or at least 0.9% of the area's non-coincidental peak load, whichever is greater, to ensure adequate regulation support.[5]
In AGC operation, the integral of the ACE over time drives generation adjustments, implementing the integral component of PI control to eliminate steady-state errors by returning ACE to zero.[24] This action dispatches upward or downward regulation signals to controllable units, restoring both tie-line flows and frequency to scheduled values within minutes.[5]
In multi-area systems, specifically denotes the difference between actual net interchange (metered flows across interconnecting tie lines) and scheduled net interchange (pre-agreed power exchanges based on economic dispatch and contracts).[24] This distinction accounts for loop flows, forecasting errors, or generation outages, enabling each area to maintain its interchange schedule without over-relying on neighboring areas for frequency support.[5]