This simulator models a generic steam-turbine governor — aggregate rotor inertia, a speed-measurement filter, a rate-limited valve actuator and a first-order turbine power response, feeding a frequency-sensitive real load. Change the load, choose droop or isochronous control, and watch how speed sensing, valve movement and mechanical power recovery bring the system back toward 50 Hz.
• A 3D cutaway of the turbine-generator and governor, with orbit, auto-rotate and expand controls, plus a component legend explaining each part's function. • A choice of network mode — island (dynamic frequency) or infinite bus (imposed frequency) — and governor mode — droop, isochronous PI (island only), or manual valve demand. • Controls to step time, add or remove load, reject load/open the breaker, and reconnect, with live metrics, an event log and a plain-language explanation panel. • Charts for frequency response, mechanical vs. electrical power balance, governor/actuator behavior (valve position vs. command), and the steady-state droop characteristic. • Guided experiments, a model-verification bench, a diagnostic challenge on droop offset, and a knowledge-check quiz.
The model is built on 2H·ω·dω/dt = Pm − Pe − Ploss: any imbalance between mechanical input and electrical demand (plus losses) changes rotor speed, which is frequency. When load increases, the rotor initially slows, using stored kinetic energy to help supply the new demand.
A droop governor commands more valve opening in proportion to speed error (command = bias + 0.02 + speed error / R), which stabilizes frequency at a new operating point below 50 Hz rather than restoring it exactly — a permanent offset. Isochronous control (island mode only) instead integrates the speed error over time to drive frequency back to setpoint. On a connected infinite bus, the model falls back to droop, since one machine alone cannot set grid frequency. Speed sensing passes through a 50 ms filter, and the actuator itself has travel lag and rate limits, so power delivery lags the command.
The model applies a teaching protection envelope: overspeed above 55 Hz for 100 ms, or underfrequency below 45 Hz for 1 s, opens the breaker and triggers an independent stop action that can override a stuck actuator. Optional under-frequency load shedding (UFLS) sheds up to 0.2 per-unit of nominal load after 200 ms spent below 48.5 Hz, illustrating how utilities protect a system from collapsing when generation can't keep up with demand.
The diagnostic challenge in the simulator asks whether a steady frequency offset after a load increase means the governor is faulty — it isn't: a droop offset is expected behavior, and restoring frequency exactly requires a secondary action (isochronous or dispatch-level control), not a repair. These are illustrative thresholds only, not recommended plant settings, and the model excludes steam thermodynamics, boiler/reheater dynamics, torsional modes and multi-machine networks.
A droop governor increases valve opening in proportion to speed (frequency) error, which stabilizes the system at a new frequency slightly off 50 Hz rather than restoring it exactly. An isochronous governor integrates the speed error over time and drives frequency back to its setpoint, but it only works on an island system — on a connected infinite bus, a single machine cannot set grid frequency, so the model falls back to droop.
The rotor and generator have inertia. When electrical load suddenly exceeds mechanical power input, the imbalance is initially covered by the rotor giving up stored kinetic energy, which shows up as a drop in rotational speed and therefore frequency. Only after the speed-measurement filter, governor logic, and rate-limited valve actuator respond does mechanical power catch up.
No. A permanent frequency offset following a load change is the expected behavior of proportional (droop) control, not a fault. Restoring frequency exactly back to 50 Hz requires a secondary action, such as isochronous control on an island system or coordinated dispatch across multiple units on a larger grid.
The simulator applies an illustrative protection envelope: overspeed above 55 Hz sustained for 100 ms, or underfrequency below 45 Hz sustained for 1 second, trips the breaker and commands an independent stop action. Optional under-frequency load shedding sheds up to 0.2 per-unit of nominal load once frequency has spent 200 ms below 48.5 Hz, mimicking how real grids shed load to arrest a frequency collapse.