This simulator models a 1-on-1 combined-cycle power plant: a gas turbine running the Brayton cycle, with its exhaust routed through a heat-recovery steam generator (HRSG) that raises steam for a separate Rankine-cycle steam turbine. Operate the plant hot and synchronized, and see how waste heat that would otherwise go up the stack is recovered into additional, fuel-free electrical output.
• A real-time 3D power island with a toggleable casing, showing both the gas turbine and steam sides, plus operating-history trends for combined, gas-only and steam-only output. • A control desk with time pause/advance, stop and hot-restart, where firing temperature settles over 2 seconds and steam availability ramps over 12 seconds after a restart. • An HRSG temperature–duty profile chart following gas cooling through superheater, evaporator and economizer sections, plus a water/steam station-measurement table and step-by-step equations. • A combined-versus-simple-cycle sweep comparing combined-cycle net MW against gas-turbine-only net MW, showing where the steam contribution becomes infeasible. • Design and loss settings, fault injection (gas compressor fouling, HRSG fouling, steam turbine erosion, condenser fouling, exhaust diverter stuck in bypass, feedwater pump failure, condenser vacuum loss), trip logic and a verification suite.
A gas turbine alone still rejects a large share of its fuel energy as hot exhaust gas, typically several hundred degrees above ambient. In a combined-cycle plant, that exhaust is not wasted: it flows through an HRSG, a heat exchanger that boils and superheats water into steam using nothing but the gas turbine's own waste heat — no additional fuel is burned for this step. That steam then drives a separate steam turbine generator, so the same fuel input that powers the gas turbine also produces a second, essentially free increment of electrical output from the steam side.
How much steam — and therefore how much extra power — can be recovered depends on the exhaust temperature available, the evaporator pinch point (the closest approach between gas and steam temperatures inside the HRSG), a minimum stack temperature, and a 20°C hot-end approach constraint. The simulator's HRSG temperature-duty profile lets you see these limits directly as you follow gas cooling against the steam-side profile.
The combined-versus-simple-cycle sweep shows the gap between gas-turbine-only output and true combined-cycle output; the sharp cutoff you may see is a model feasibility boundary — the point where the fixed steam-temperature target can no longer satisfy the 20°C hot-end approach — not a real plant trip curve. Condenser pressure on the steam side is a prescribed input rather than a free variable; the cooling-loop readouts instead report whether the selected cooling equipment can actually support that pressure.
Illustrative plant trips activate on gas turbine inlet temperature above 1550 K, feedwater pump failure, a vacuum-loss signal, or condenser pressure above 40 kPa. This is a teaching model coupling a variable-cp air-standard gas turbine to an IAPWS-table Rankine steam cycle through a single-pressure, unfired or duct-fired HRSG — it omits multi-pressure/reheat hardware, cooling bleeds, combustion chemistry, drum inventory, detailed heat-transfer surfaces, emissions, and startup/grid transients, and it is not an OEM performance predictor.
The gas turbine's exhaust is routed directly into a heat-recovery steam generator (HRSG) that produces steam for a separate steam turbine, so the two cycles are thermally coupled: gas turbine exhaust conditions set how much steam the HRSG can raise, and that steam output adds directly to the plant's net electrical generation without burning additional fuel for that increment.
The heat driving the steam cycle comes entirely from gas turbine exhaust that would otherwise be rejected up the stack. Since no additional fuel is burned to raise that steam (in the unfired HRSG case), the steam turbine's output improves overall plant efficiency without a proportional increase in fuel consumption.
Three constraints: the evaporator pinch point (the closest temperature approach between the cooling exhaust gas and the boiling water/steam), a minimum allowable stack temperature, and a 20°C hot-end approach at the superheater. When available exhaust heat can no longer satisfy these together at a given steam-temperature target, the model treats further steam production as infeasible.
Illustrative plant trips on gas turbine inlet temperature above 1550 K, feedwater pump failure, a condenser vacuum-loss signal, or condenser pressure above 40 kPa. Condenser pressure itself is a prescribed input; cooling-related faults instead generate a capacity warning about whether the selected cooling equipment can support that prescribed pressure.