Frequency response & AGC — inertia, droop, ACE, three response layers

Reference notes

Power balance — generation must equal load plus losses at every instant. Any imbalance forces system frequency to change at a rate set by total system inertia. The grid responds in four layers: inertial (0-5 s, physics), primary (1-30 s, governor droop), secondary (1-15 min, AGC drives ACE to 0), and tertiary (15 min+, SCED markets). NERC BAL-001/002/003 standards govern performance; PRC-006 UFLS is the last-line-of-defense protection.

Swing equation and the inertia constant

• H — inertia constant — defined as kinetic energy stored in rotating mass at synchronous speed divided by rated MVA, units of seconds.
• Typical values:
  • Steam turbine: 3-5 s
  • Hydro turbine: 6-8 s
  • Nuclear: 8-12 s
  • Combustion turbine: 1-3 s
  • Inverter-based (wind, solar, battery): 0 s unless artificially provided by grid-forming inverter control
• Higher H = slower frequency response to disturbances ("flywheel buffer").
• ROCOF (Rate Of Change Of Frequency) right after an imbalance is set by H_sys.

Inertial response (0-5 s)

• Kinetic energy of rotating mass cushions the imbalance during the first few seconds.
• Pure physics; no control action.
• Example: 1000 MW trip on PJM (~150 GW peak) with H_sys = 5 s → ROCOF ≈ 0.05 Hz/s; nadir ≈ 59.85 Hz before primary acts.
• Low-inertia case (Hawaii, Ireland, ERCOT during high wind): same trip on H_sys = 1.5 s → ROCOF ≈ 0.20 Hz/s (3-5× faster).

Primary frequency response (1-30 s) — governor droop

• Automatic, decentralized — every responsive generator's GOVERNOR responds to local frequency.
• Droop R = governor gain. Typical R = 5% — meaning a 5% change in frequency (3 Hz on 60 Hz) swings the generator from no output to full output.
• System aggregate droop (weighted by capacity): typically 0.5-1.5% in a fully-staffed bulk power system.
• Result: frequency stabilizes at QUASI-STEADY value 0.05-0.20 Hz below nominal — needs secondary control to restore to nominal.
• Frequency NADIR (lowest during transient): typically 0.1-0.4 Hz below nominal.
• Resources: partial-loaded generators with spinning reserve, demand response, batteries with FFR (Fast Frequency Response).
• NERC BAL-003 — Frequency Response Standard — defines per-area Frequency Response Obligation (FRO).

Secondary control (1-15 min) — AGC

• Automatic Generation Control (AGC) at each Balancing Authority's control center.
• Measures local frequency f and tie-line flows P_tie every 2-6 seconds.
• Computes Area Control Error (ACE):
  • ACE > 0 → area exporting more than scheduled OR over-generating (frequency high).
  • ACE < 0 → area under-generating.
• PI controller commands AGC-enabled generators to drive ACE → 0.
• AGC-enabled resources typically 5-10% of area load capacity: thermal generators with regulation capability, hydro (excellent ramp rate), batteries (instantaneous ramp).
• Restores frequency to nominal AND tie-line flows to scheduled values.

Tertiary control (15 min+) — SCED & reserves

• SCED (Security-Constrained Economic Dispatch) runs every 5-15 minutes — see L8 OPF/SCED.
• Re-economizes generator dispatch subject to network constraints.
• Replenishes spinning reserves.
• Market-clears energy + ancillary services every dispatch interval.

Operating reserve products

• OPERATING RESERVE = regulation + spinning + supplemental.
• NERC BAL-002 requires sufficient operating reserve to cover the largest single contingency (N-1).
• All reserve products co-optimized with energy in SCED; opportunity cost reflected in clearing prices.

Inertia & the IBR (inverter-based resource) challenge

• Traditional grid (100% synchronous): H_sys = 3-6 s typical.
• High-IBR grids (Hawaii Oahu, Ireland Eirgrid, AEMO South Australia, ERCOT high wind): H_sys can drop to 1-2 s.
• Consequences of high ROCOF:
  • DG ROCOF protection (typical threshold 0.5-1.0 Hz/s) trips cascade.
  • Frequency nadir lower — UFLS triggers earlier.
  • Smaller margin for primary response.
• Mitigation strategies:
  • Synchronous condensers at key buses — see L11 synchronous-condenser.
  • Grid-forming inverters — IBR control mode providing voltage-source behavior and synthetic inertia. Pilots at AEMO, Hawaii.
  • Fast Frequency Response (FFR) — batteries responding in 100-500 ms to ROCOF. UK National Grid EFR market clears 200-500 MW battery FFR daily.
  • Minimum-inertia operating constraints — Ireland, AEMO, Hawaii enforce minimum H_sys in operations.

NERC BAL standards

UFLS — Under-Frequency Load Shedding (PRC-006)

• Automatic last-line-of-defense protection that sheds load in steps when frequency falls.
• Typical scheme: 5% of load shed at 59.5 Hz; 5% more at 59.3 Hz; 5% more at 59.1 Hz; continuing in 0.2-0.4 Hz steps down to 58.5 Hz.
• Coordinated across all Balancing Authorities to distribute load shedding appropriately.
• Time delays at each step (0.05-0.5 s) prevent unnecessary tripping on momentary excursions.
• Restoration: after frequency recovers (60 Hz ± 0.1), operators pick up shed load in coordinated blocks.
• Related: PRC-024 defines generator off-nominal frequency capability (57.5-61.5 Hz ride-through); IEEE 1547 DER ride-through.

Real-time monitoring

• EMS displays frequency, ACE, area reserves, AGC status continuously.
• SCADA samples at 2-6 Hz typical for AGC.
• PMUs sample at 30-120 Hz for fast-event analysis (post-disturbance forensics, ROCOF, oscillation detection).
• Post-disturbance review via NERC GADS (Generating Availability Data System) and BAL-003 reporting.

Ancillary-service markets

• PJM, CAISO, MISO, NYISO, ISO-NE, ERCOT all co-clear regulation, spinning reserve, and operating reserve markets every dispatch interval.
• Prices reflect scarcity of reserve when system is stressed.
• Settlement: areas pay or receive INADVERTENT INTERCHANGE based on cumulative ACE imbalance per NERC BAL-001.