Generation Control

Automatic Generation Control (AGC) Overview

AGC is the cornerstone of generation control, providing closed-loop regulation of system frequency and net interchange to scheduled values. It operates on 2-6 second cycles, continuously adjusting generator outputs.

AGC Logic & Control Approaches

All of these should be reviewed and set to reasonable values prior to the start of generating unit tuning. AGC allows the user to control the system using one of two different approaches:

Traditional AGC Control
Short Term CPS Control

Traditional AGC Control: The main goal is to control the filtered ACE signal calculated depending upon operator selected method: Constant Net Interchange (CNI), Constant Frequency (CF), Constant Frequency and Time Control (CFT), Tie-line Bias Control (TLB), Tie-line Time Bias (TLTB), or Constant Power Production (CPP). Therefore, if traditional AGC control is selected, ACE filter in particular may require tuning and may need to be adjusted throughout the tuning process.

Short-Term CPS Logic: Computes the portion of the MW Requirement that is calculated based on a permissible operating region defined in terms of the system frequency error and the tie line error, which is defined by the intersection of the CPS1 and CPS2 operating limits (the Green Zone). The CPS logic computes the MW needed to fix the most restrictive problem with the CPS2, CPS1, Inadvertent Pay Back (PYBK) and Green Zone (GNZN) control drivers, in that priority order.

Frequency

±0.02 Hz typical

Interchange

MW schedule tracking

ACE

Error signal

ACE Calculation Methods

Area Control Error (ACE) is the driving signal for AGC. Multiple calculation methods available for different operating modes:

Method	Formula
CF	ACE = -10Bf × (fa - fs)
CNI	ACE = Ia - (Is + Iic + Ids) + Ime
TLB	ACE = (Ia - Is) + (-10Bf)(fa - fs)
TLTB	ACE = TLB + 10Bt × Dt
CFT	ACE = CF + 10Bt × Dt
CPP	ACE = Pa - Ps + Po

Variables:

fa = Actual frequency (Hz)
fs = Scheduled frequency (Hz)
Bf = Frequency bias (MW/0.1Hz)
Ia = Actual interchange (MW)
Is = Scheduled interchange (MW)
Iic = Inadvertent correction
Ids = Dynamic schedule
Bt = Time bias (MW/0.1 sec)
Dt = Time error (sec)

Tie Line Bias (most common):
ACE = (Ia - Is - Iic - Ids + Ime) + (-10Bf)(fa - fs) + 10Bt(Dt)

Unit Control Modes

Each generator under AGC can operate in different modes based on its role and availability:

AUTO Full AGC

ECON Economic

RAMP Ramping

BASE Baseload

BREG Base+Reg

SCHD Scheduled

SREG Sched+Reg

MANL Manual

MAND Manual Dispatch

AVAL Available

UNAV Unavailable

TEST Test

PUMP Pumping

SYNC Sync Cond

Unit Limits and Constraints

Low Capability (50 MW)

Low Econ (75 MW)

Low Reg (100 MW)

High Reg (200 MW)

High Econ (225 MW)

High Cap (250 MW)

Regulating Range Economic Range Capability Limits

Economic Dispatch Integration

Participation Factor Calculation

PFᵢ = (1/ICᵢ) / Σ(1/ICⱼ)
Where ICᵢ = ∂Fᵢ/∂Pᵢ (Incremental Cost)

With Transmission Losses

Penalty Factor PF = 1 / (1 - ∂PL/∂Pᵢ)
Modified: ICᵢ × PFᵢ = λ (System Lambda)

Real-Time Optimization: Economic Dispatch executes every 2-4 minutes or on significant system changes (load change > 50 MW, unit status change)

NERC Performance Standards

CPS1 (Control Performance Standard 1)

CPS1 = (2 - CF_avg) × 100%
Requirement: ≥ 100% over 12 months

CPS2 (Control Performance Standard 2)

ACE_10min ≤ L10
L10 = 1.65 × ε10 × √((-10B) × (-10B_s))

Worked Example

Input Data:

Area load: 5000 MW
Bias B = 250 MW/0.1Hz
Scheduled freq: 60.00 Hz
Actual freq: 59.98 Hz
Sched interchange: 200 MW
Actual interchange: 180 MW
Time error: +2 sec
Time bias Bt = 25 MW/0.1sec

Calculation:

                    1. Frequency component = -10×250×(59.98-60.00) = +50 MW

                    2. Interchange component = 180 - 200 = -20 MW

                    3. Time component = 10×25×2 = 500 MW (limited to 50 MW)

                    4. ACE (TLB) = -20 + 50 = +30 MW

                    5. ACE (TLTB) = -20 + 50 + 50 = +80 MW

                    Interpretation: Area has excess generation, reduce by 80 MW