Governing Dynamics of Gas and Steam Turbines in Primary Frequency Response: Understanding Models and Real-World Behavior

In modern power systems, stability is everything. Whether in a vast interconnected grid or an islanded operation, maintaining frequency is the heartbeat of reliability. Among the critical players ensuring this stability are gas turbines (GTs) and steam turbines (STs) and at the core of their contribution lies the Primary Frequency Response (PFR).

But how do these turbines actually respond in PFR events? And more importantly, how are their governors modeled so system operators, planners, and engineers can trust their simulations? Let’s break it down.

What is Primary Frequency Response?

Primary Frequency Response is the immediate, automatic change in generator output when system frequency deviates from its nominal value (50 or 60 Hz).

• When frequency drops (loss of generation, sudden load increase), governors increase turbine output.
• When frequency rises (loss of load, generation overshoot), governors reduce output.

This action happens in the first 5–30 seconds after a disturbance and is crucial to arrest frequency decline before secondary (AGC) and tertiary (manual dispatch) controls take over.

Both gas and steam turbines provide PFR, but their speed, inertia, and control philosophies differ significantly.

Gas Turbines in PFR: Fast but Constrained

Gas turbines are prized for their fast response characteristics. Their light rotating mass means less inertia than steam turbines, but they can ramp fuel quickly.

How GT Governors Work

Gas turbine control can be simplified into three main loops:

1. Speed/Load-Frequency Control Loop – Active during normal operation, adjusting fuel flow to match load demand or frequency deviation.
2. Temperature Control Loop – Prevents firing temperature from exceeding design limits by modulating fuel and air flow.
3. Acceleration Control Loop – Limits rate of change during startup/shutdown.

For frequency response, the speed/load-frequency loop dominates. In droop mode, when system frequency falls, the governor opens fuel valves, increasing output. Conversely, when frequency rises, fuel input is reduced.

The Rowen Model: Industry Benchmark for GTs

When engineers talk about GT modeling in stability studies, one name comes up repeatedly: Rowen’s model (1983).

• It is a simplified mathematical model for heavy-duty single-shaft GTs.
• The model uses transfer functions to represent: Governor dynamics (droop, deadband, valve limits). Fuel system time constants (delays in combustion). Compressor and turbine response (represented with inertia and gain factors).

Why Rowen’s model matters:

• It’s simple enough for system-wide studies.
• It captures the essentials of PFR: governor action, ramp constraints, and fuel-air dynamics.
• Still widely used today in commercial software like PSSE, DIgSILENT, and PSCAD as the basis for GT blocks

More advanced models expand Rowen’s work with temperature limits, variable inlet guide vane (VIGV) dynamics, and nonlinear combustion response, but the Rowen model remains the cornerstone for PFR analysis of GTs.

Steam Turbines in PFR: Slow but Stable

Steam turbines, especially those in large thermal plants, bring something gas turbines lack: inertia. Their heavy rotors resist frequency change, naturally damping oscillations.

How ST Governors Work

Steam turbine-governing systems are classically modeled with:

• Governor Time Constant (Tg) – Delays in valve control action.
• Turbine Time Constant (Tc) – Reflects steam chest dynamics.
• Reheat Time Constant (Tr) – Important in multi-stage steam turbines.
• Damping and Regulation Constant (R, D) – Capture steady-state frequency-power relation.

These time constants mean steam turbines respond slower than gas turbines. But the sheer inertia they contribute is invaluable to system stability, especially in large disturbances.

Single-Shaft vs Multi-Shaft Combined Cycle Plants

In practice, many power plants operate as Combined Cycle Gas Turbine (CCGT) units — pairing GTs with STs. How they are mechanically coupled has a major impact on frequency response:

1. Single-Shaft Configuration One gas turbine, one steam turbine, and one generator mounted on a common shaft. Advantages: Simpler startup sequence. Compact footprint. Lower capital cost. Drawbacks: Less operational flexibility, both turbines must run together. Frequency response is coupled; GT’s fast action and ST’s slow action are locked on the same shaft.
2. Multi-Shaft Configuration Each gas turbine drives its own generator, while one or more steam turbines drive another generator. Advantages: Independent operation of GTs and STs. More flexible in partial load or during grid support. Drawbacks: Higher cost and footprint. More complex plant integration.

From a PFR perspective:

• Single-shaft units behave like one combined machine with mixed dynamics — stable but less flexible.
• Multi-shaft units allow GTs to provide fast PFR independently, while STs contribute inertia and steady support. This makes them more adaptable in modern grids where fast frequency containment is critical.

The Hybrid Challenge: GTs and STs Together

When gas and steam turbines operate together in combined-cycle or hybrid power plants, the differences in their dynamic responses can lead to challenges:

1. Oscillations – GTs react quickly, STs lag. This mismatch can cause power oscillations between the two.
2. Frequency Deviation – Adding GTs reduces system inertia, making nadirs deeper unless compensated.

Xiong et al. (2022) studied this effect in a Chinese power plant with 14 gas turbines and 2 steam turbines

They found significant oscillations and larger frequency swings when GTs were integrated without additional controls.

Advanced Control Strategies for Better PFR

To address these challenges, modern research is introducing supplementary controls:

1. Voltage Addition Strategy – By slightly adjusting excitation voltage based on frequency deviation, oscillations between GTs and STs can be suppressed.
2. Power Addition Strategy – GTs absorb more load when frequency deviation exceeds a threshold. Since GTs adjust quickly, they take the brunt of the frequency event, while STs stabilize later

The outcome? In test cases, these strategies reduced frequency oscillations and improved nadir performance, in simple words it prevents frequency from dropping too low, proving that coordinated hybrid control is key in modern systems.

Practical Implications for Engineers

For practicing engineers and operators, understanding PFR dynamics is more than academic:

• Grid Compliance: Many grid codes (e.g., ENTSO-E, NERC) require generators to provide PFR within defined droop and response times.
• Governor Tuning: Droop, deadband, and ramp limits must be set correctly — too aggressive can destabilize, too sluggish can fail compliance.
• Plant Configuration Awareness: Whether a plant is single-shaft or multi-shaft directly affects how PFR is delivered.
• Islanding Events: In islanded grids, one unit may need to run in isochronous mode, while others stay in droop to share load.

Closing Thoughts

The dance between gas turbines and steam turbines in primary frequency response is a fascinating balance of speed and inertia. Gas turbines deliver agility, steam turbines deliver stability, and together they safeguard the heartbeat of our power systems.

As grids evolve — with renewables displacing conventional inertia — the role of accurate governor modeling, whether through Rowen models or advanced nonlinear simulations, will only grow. For engineers, mastering these dynamics is not just about compliance; it’s about ensuring that when the next big disturbance hits, the lights stay on.

References

• Iliescu, S. S., Făgărăşan, I., Popescu, V., & Soare, C. (2008). Gas turbine modeling for load-frequency control. U.P.B. Sci. Bull., Series C, Vol. 70, Iss. 4.
• Xiong, J., Ding, Y., Ye, H., Pei, W., & Kong, L. (2022). The additional control strategies to improve primary frequency response for hybrid power plant with gas turbines and steam turbines. Energy Reports, 8, 557–564.