How a combined-cycle gas power plant works
A combined-cycle plant recovers more energy from its fuel: a gas turbine generates electricity, then its hot exhaust makes steam for a second turbine.
In 60 seconds: how it works
A combined-cycle plant gets electricity from its fuel twice. A gas turbine makes power first, then its hot exhaust makes steam that drives a second turbine.
- Air is squeezed by a compressor and mixed with natural gas, which burns in a combustor.
- The hot gases expand through the gas turbine, spinning it and its generator.
- The exhaust is still very hot, so it passes through a heat-recovery boiler that turns water into steam.
- The steam drives a steam turbine and a second generator.
- The steam is condensed back into water and reused.
- A transformer raises the voltage so the electricity can travel to the grid.
Want the engineering detail? Explore the 3D model, then read the engineering notes and the types and variations.
By Power Stations Worldwide · Related reading updated · Preparation and review scope. Educational illustrations; no independent engineering peer review is claimed.
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1+1 multi-shaft combined cycle: two independent generator trains. Unfired single-pressure HRSG and dry air-cooled condenser. Three bounded steady teaching cases use one fuel/heat/electricity balance, not a calibrated part-load or shutdown model. Internals and distances are simplified for inspection. Motion is slowed for inspection. Coloured overlays reveal flow through enclosed equipment; gold pulses show net electrical energy transfer, not individual electrons.
How it works
- Fuel energy
- Combustion heat
- Gas-turbine + steam-cycle work
- Generators
- Grid electricity
A gas-fired station converts fuel energy into shaft rotation and then electrical power. In a gas turbine, air is compressed before fuel burns in it. Expanding hot gas turns turbine blades, supplying both the compressor and the generator. This continuous-flow arrangement follows the Brayton-cycle principle. The compressor consumes a substantial part of the turbine’s mechanical output, so the generator receives the remaining shaft power rather than everything the turbine develops.
The illustrated 1+1 multi-shaft combined cycle adds a separate steam-turbine generator. Its unfired single-pressure heat-recovery steam generator transfers exhaust heat across tube walls without mixing gas and water or adding another fuel input. The water/steam cycle uses a dry air-cooled condenser and feed pump. Both generators have independent switchgear/transformer exports. The bounded cases below account for compressor work once, then generator losses, electrical auxiliaries and transformer losses; they are not a validated part-load or time-domain plant simulation.
Use the hot exhaust twice. Count the fuel once.
The model shows a 1+1 multi-shaft combined cycle: one gas-turbine train plus one steam-turbine train, two generators, a single-pressure heat-recovery steam generator (HRSG) and dry air-cooled condenser (ACC). It is an invented learning case, not the specification of a named station.
Selected: whole-system overview.
Simple explanation
The first turbine powers its own compressor. Rotating compressor blades add work to incoming air; fixed vanes guide and diffuse the flow. Fuel burns in compressed air. Hot gas expands through turbine rows, driving the compressor and generator G1 on the same shaft. Only the work remaining after compressor consumption reaches that generator. The cutaway distinguishes moving blades from fixed vanes and supports. [G4]
Exhaust heat makes steam without mixing fluids. Gas passes outside HRSG water/steam tubes. Feedwater warms in the economiser, circulates between drum and evaporator, and separated steam passes through the superheater. That steam drives a separate turbine and generator G2. This unfired HRSG has no additional fuel input: its heat is transferred from the GT exhaust already counted in the fuel ledger. [G1] [G7]
Dry cooling closes the water cycle. Steam condenses inside finned tubes while fans pass ambient air across their outside surfaces. Condensate returns through the feed pump. No wet-tower plume is appropriate here. Pumps, fans, generators and transformers reduce net electricity. Hot ambient conditions affect real ACC performance, but this model fixes condensing pressure instead of predicting weather effects. [G1] [G6]
Current power balance
| Boundary | Power |
|---|---|
| Fuel LHV input (whole-plant input) | 218.037 |
| Gas turbine work before compressor deduction | 165.124 |
| Compressor shaft consumption · deducted once | 94.750 |
| Gas train net shaft work | 70.374 |
| HRSG recovered heat · internal transfer | 87.038 |
| Steam turbine shaft work | 28.829 |
| Combined gross electricity | 97.219 |
| Feed-pump fluid work | 0.286 |
| Feed-pump electrical consumption | 0.301 |
| Other electrical auxiliaries | 1.944 |
| Gas-turbine generator export | 67.249 |
| Steam-turbine generator export | 27.249 |
| Total net export | 94.499 |
| ACC heat rejection | 58.495 |
| Stack sensible heat above ambient reference | 56.990 |
| Total unexported power budget | 123.539 |
218.037 MWth fuel = 94.499 MWe net export + 123.539 MW unexported budget.
The unexported budget includes stack sensible heat, condenser heat, heat-addition and HRSG allowances, generator/motor/transformer losses and other auxiliaries. It is not a calculated greenhouse-gas emissions figure. Recovered heat is an internal transfer, not extra fuel or a second loss. Pump work added to water is already in the steam heat balance.
Budget breakdown in MW: stack 56.990 + ACC 58.495 + combustion heat-addition allowance 2.180 + HRSG ambient allowance 1.455 + generator losses 1.984 + pump-motor loss 0.015 + other auxiliaries 1.944 + transformer losses 0.475 = 123.539. Allowances are illustrative, not measured equipment losses.
Measurement states from the same model
Air 250.000 kg/s + fuel 4.361 kg/s = exhaust 254.361 kg/s. Steam/feedwater flow is 28.338 kg/s. Unrounded whole-plant balance residual: 1.49e-8 W.
| Boundary | p kPa | T °C | h kJ/kg |
|---|---|---|---|
| G1 · Ambient inlet air | 101.325 | 15.000 | 0.000 |
| G2 · Compressor outlet | 1418.550 | 392.115 | 379.000 |
| G3 · Turbine inlet | 1361.808 | 1076.850 | 1221.128 |
| G4 · Gas-turbine exhaust | 101.325 | 512.352 | 571.955 |
| G5 · HRSG after heat allowance | 101.325 | 507.378 | 566.235 |
| G6 · Stack outlet | 101.325 | 209.826 | 224.050 |
| Boundary | p MPa | T °C | h kJ/kg | s kJ/(kg·K) | Quality x |
|---|---|---|---|---|---|
| S1 · Condenser liquid | 0.010 | 45.806 | 191.810 | 0.6492 | 0.0000 |
| S2 · Feed-pump outlet | 8.000 | Not calculated | 201.900 | Not calculated | Not applicable |
| S3 · Economizer outlet | 8.000 | 280.000 | 1236.000 | 3.0631 | Not applicable |
| S4 · Superheated main steam | 8.000 | 450.000 | 3273.300 | 6.5579 | Not applicable |
| S5 · Steam-turbine exhaust | 0.010 | 45.806 | 2255.988 | 7.1207 | 0.8629 |
| Drum saturated steam | 8.000 | 295.008 | 2758.700 | Not calculated | 1.0000 |
| Section | Heat MW | Gas inlet °C | Gas outlet °C |
|---|---|---|---|
| Superheater · hot end | 14.583 | 507.378 | 457.525 |
| Evaporator + remaining liquid warming | 43.151 | 457.525 | 310.008 |
| Economizer · cold end | 29.305 | 310.008 | 209.826 |
Evaporator pinch 15.000 K; economiser water approach 15.008 K; hot-end gas-to-main-steam approach 57.378 K. Steam-flow constraint: pinch. Stack gas 209.826 °C. These positive differences are checked, not independently animated values.
Engineering details: bounded steady-state calculation
Temperature T is in kelvin (K), pressure p in pascals (Pa), mass flow ṁ in kg/s, heat-capacity ratio γ dimensionless and specific heat cₚ in J/(kg·K). Heat rate Q̇ and power P use watts (W). Enthalpy h is energy per mass, tabulated in kJ/kg and converted to J/kg for power. Entropy s uses kJ/(kg·K); specific volume v uses m³/kg. Efficiency η is dimensionless; Δ means a difference. LHV is lower heating value, excluding recovery of water-vapour condensation energy in combustion products. No higher-heating-value (HHV) efficiency is reported.
T₂ = T₁[1 + ((p₂/p₁)^((γair−1)/γair) − 1)/ηC]
T₄ = T₃[1 − ηGT(1 − (p₄/p₃)^((γgas−1)/γgas))]
P_C = ṁair cₚ,air(T₂−T₁)
P_GT,net shaft = (ṁair+ṁfuel)cₚ,gas(T₃−T₄) − P_C
States 1–4 are ambient inlet, compressor exit, combustor exit and gas-turbine exit. C denotes compressor, GT gas turbine. We approximate air and combustion gas with constant effective specific heats, not a species-dependent property calculation. Fuel mass is included in turbine/exhaust flow. The heat-addition balance gives fuel/air ratio f = [cₚ,gas(T₃−T₁)−cₚ,air(T₂−T₁)]/[ηheat LHV−cₚ,gas(T₃−T₁)]. This is not a flame-temperature or emissions model. [G4]
Illustrative constants: ambient 288.15 K/101.325 kPa; cₚ,air=1005 and cₚ,gas=1150 J/(kg·K); γair=1.4, γgas=1.33; ηC=0.86, ηGT=0.88; combustor pressure retention 0.96 and heat-addition efficiency 0.99; fuel LHV 50 MJ/kg. Reference: 250 kg/s air, pressure ratio 14, T₃=1350 K. Reduced comparison: 175 kg/s, ratio 10, T₃=1250 K. No downstream exhaust pressure drop, compressor map, surge margin, variable guide-vane control or transient is calculated.
Q̇_SH = ṁsteam(h_main−h_g,8MPa)
Q̇_EV = ṁsteam(h_g,8MPa−h_EC)
Q̇_EC = ṁsteam(h_EC−h_feed)
Q̇_recovered = Q̇_SH + Q̇_EV + Q̇_EC
Gas passes SH → EV → EC in this selected arrangement. Feedwater goes EC → drum/EV circulation → SH; hot gas never enters the water loop. Subscript g means saturated vapour, main main steam. EC outlet is 8 MPa/280 °C; 8 MPa saturation is 295.008 °C. EV duty includes the remaining liquid warming before boiling, not latent heat alone. Drum circulation is conceptual; no invented internal recirculation flow rate is displayed. [G5] [G7]
Cgas = ṁgas cₚ,gas
ṁsteam = min[Cgas(T_hot−120 °C)/(h_main−h_feed), Cgas(T_hot−T_sat−15 K)/(h_main−h_EC)]
Cgas is the gas-stream heat-capacity rate in W/K. T_hot follows a 1% exhaust-heat ambient allowance. Celsius temperature differences equal kelvin differences; all terms in each subtraction use the same reference. The two bounds enforce a 120 °C minimum stack temperature and 15 K minimum evaporator-outlet pinch. The EC water approach is 15.008 K. These are illustrative thermal constraints, not acid-dew-point, boiler surface-area or off-design safety checks. No supplementary firing, blowdown or steam pressure-drop model is included.
w_pump = v_f Δp / ηpump; h_feed = h_f,10kPa + w_pump
x_s = (s_main−s_f)/(s_g−s_f); h_s = h_f + x_s(h_g−h_f)
h_out = h_main − ηST(h_main−h_s)
Q̇_recovered + P_pump,fluid = P_ST,shaft + Q̇_ACC
Here f/g denote saturated liquid/vapour at the stated pressure; x is vapour mass fraction, not volume fraction; subscript s means isentropic (constant entropy). Main steam is 8 MPa/450 °C; condenser pressure is 10 kPa (0.010 MPa). The steam-turbine efficiency ηST=0.85, pump hydraulic efficiency 0.80 and motor efficiency 0.95 are invented example values. Pump outlet enthalpy is derived with an incompressible approximation; outlet temperature is not calculated. The condenser saturation temperature is 45.806 °C. [G3] [G5]
The calculated turbine exhaust is wet steam: reference quality 0.8629, or 13.71% liquid by mass. There is no reheat here. This is a learning result, not an acceptable blade-moisture limit, qualified turbine operating point or vendor guarantee.
P_gross,total = 0.98(P_GT,net shaft + P_ST,shaft)
P_aux = 0.02 P_gross,total + P_pump,fluid/0.95
P_net = 0.995(P_gross,total − P_aux)
η_net,LHV = P_net / P_fuel,LHV
The 2% other-auxiliary allowance excludes both the already deducted compressor and the separately calculated feed pump. Generator efficiency 0.98 and transformer efficiency 0.995 are illustrative, not vendor guarantees. The feed pump is assigned to the ST branch; each branch pays its own 2% auxiliary allowance and transformer loss. No excitation, synchronisation, reactive-power, protection or AC network calculation is performed.
n = 120 f_grid / p_poles = 120 × 50 / 2 = 3000 rpm; ω = 2πn/60; τ = P_shaft/ω
Here n is physical rotational speed, f_grid grid frequency, p_poles total poles (not pole pairs), ω angular speed in radians/s and τ torque in newton-metres. Equal speeds do not join the two shafts. Display speed and pause are visual controls, not physical frequency changes. Flow pulses indicate direction, not fluid speed or electron motion. [G2]
Checked reference example · not a real plant rating
Fuel 218.037 MWth (LHV); compressor consumes 94.750 MW of the gas turbine’s 165.124 MW. GT net shaft 70.374 MW; ST shaft 28.829 MW; gross electricity 97.219 MWe; auxiliaries 2.245 MWe. Total net export 94.499 MWe plus unexported budget 123.539 MW balances the fuel input before rounding. The worked values and animated state use the same pure calculation.
Mechanical cutaway and limitations
Rows of fixed guide vanes face rotating blades, while bearings support a continuous shaft inside a bore. Turbine work turns its compressor and generator; the independent steam train has a separate coupling. HRSG supports carry tube banks and drum; pressure-containing tube walls separate fluids. The ACC has overhead headers and finned tubes with fans below. Removed wall sectors, compressed routes, simplified tube/blade counts and enlarged internals improve visibility. No stress, vibration, thermal-growth, fire/explosion, pressure-vessel, insulation-clearance or standards-compliance check is claimed.
Simple cycle is a comparison, not a relabelled mode
An open-cycle gas turbine has no bottoming steam plant. It still powers its compressor before exporting electricity and rejects its remaining exhaust energy. This model does not add an unmodelled exhaust bypass or claim to simulate simple-cycle switching. Read the separate simple-cycle description. Combined-cycle heat recovery gains output but adds steam, cooling, water-treatment and control equipment; it does not remove combustion emissions. [G1]
Check your understanding
Should compressor work also be subtracted from electrical auxiliaries?
No. It has already been taken from gas-turbine shaft work before generator conversion. Subtracting it again would double-count the same consumption.
Does the HRSG provide a second fuel input?
Not in this unfired case. It transfers previously counted exhaust heat through tube walls into the water/steam cycle. Some real HRSGs use supplementary firing; that is not modelled here.
Are the gas and steam turbines connected by one shaft?
No. This multi-shaft plant has two independent turbine-generator trains. The compressor shares the gas-turbine shaft, not the steam-turbine shaft.
Books and complementary foundations
Selected actual passages checked . Original lesson, software and geometry checks; not independently engineering peer reviewed. Only the stated passages were read, not every chapter of each book.
- [G1] Kehlhofer, Rukes, Hannemann & Stirnimann. Combined-Cycle Gas & Steam Turbine Power Plants, 3rd ed., PennWell, 2009, ISBN 9781593701680. Publisher record; lawful sample, printed pp. 1, 40, 61: combined-cycle principle, unfired heat recovery and direct-air-cooling tradeoffs. Earlier definitions around equation 4–8 and full machinery/part-load chapters are unavailable in this sample; no complete-book verification or adoption of its historical example ratings is claimed.
- [G2] Woodson & Melcher. Electromechanical Dynamics, Part I, Wiley, 1968. Lawful MIT Chapter 4, §4.1.8, equation 4.1.95, for synchronous pole/speed relation.
- [G3] DOE. Thermodynamics, Heat Transfer, and Fluid Flow, DOE-HDBK-1012/1-92, Vol. 1, 1992. Official teaching handbook, printed pp. 79–82, 84, 90–91: steady turbine, pump and separate-stream heat balances.
- [G4] NETL. Gas Turbine Handbook. Boyce, Axial-Flow Compressors §2.0-1, first technical page; Brouwer, Hybrid Gas Turbine Fuel Cell Systems §1.4, printed p. 143, generic compressor/turbine relations. Hybrid context, not this plant’s performance map; individual section PDFs do not state a publication date.
Supplementary primary technical sources
- [G5] Allan H. Harvey. Thermodynamic Properties of Water, NISTIR 5078, 1998, IAPWS-95. Table 2, printed pp. 11/14; Table 3, printed pp. 52–53. Actual selected rows checked: 8 MPa/450 °C h=3273.3 kJ/kg, s=6.5579 kJ/(kg·K); 8 MPa/280 °C h=1236.0; saturated 8 MPa h_f=1317.3, h_g=2758.7; 10 kPa h_f=191.81, h_g=2583.9, s_f=0.64920, s_g=8.1488, v_f=0.00101027 m³/kg. Rounded endpoints are subtracted consistently; no full property solver is implemented.
- [G6] Turner, Pidaparti & Grol. Advanced Water-Related Technology Performance Development, DOE/NETL-2021/2755, 2021. §2.2.4, printed p. 28 checked for apex steam headers, finned tubes, fans and condensate collection. Coal-plant context; no coal ratings transferred.
- [G7] Esteem Projects. HRSG Learning Center, undated. Section arrangement; single-pressure heat balance, pinch and water approach. Actual technical passages checked; selected sequence is not universal. No vendor design values or source illustrations copied.
Download the editable original Blender scene · Download the optimized browser model. Reproduction, calculation and validation details accompany the source repository. Educational examples are not approved installation designs.
Inside the engineering
Follow the machinery, the working fluids and the electrical connection.
Mechanical
An axial compressor, combustors and expansion turbine form the gas-turbine train. The turbine drives both its compressor and generator. A separate steam turbine uses recovered exhaust heat, with an air-cooled condenser returning water to the feedwater circuit.
Thermal & chemical
Fuel burns in compressed air. The gas turbine follows the Brayton-cycle principle; the heat-recovery steam circuit follows the Rankine-cycle principle. Exhaust gas and steam exchange heat across tube walls without mixing. Combustion produces CO₂ and can form nitrogen oxides.
Electrical
Each two-pole, 50 Hz generator has its own shaft, switchgear and step-up transformer export. Positive-case physical speeds are 3000 rpm, separately slowed for display. Compressor work is deducted once before GT generation; net exports also subtract generator losses, electrical auxiliaries and transformer losses.
Main types and variations
The model shows a combined-cycle plant with separate gas- and steam-turbine generators. These alternatives describe machinery and heat use, not different names for the fuel. A gas engine, a gas turbine and a CHP installation can all consume natural gas; approved alternative fuels depend on the equipment.
Open-cycle gas turbine
Also called simple cycle, this arrangement generates electricity from the gas-turbine shaft without a bottoming steam turbine. Air enters, fuel burns and the exhaust leaves after expansion. The turbine still drives its compressor as well as its generator, and much of the unused energy leaves as exhaust heat.
What changes in practice
Removing the steam plant simplifies the installation. Compared with adding heat recovery for power generation, more fuel energy remains unused in the exhaust.
Combined-cycle gas turbine
A heat-recovery steam generator captures gas-turbine exhaust energy for a steam turbine. The two cycles share an energy source while keeping their working fluids separate. Plants may put the turbines on a common generator shaft or use separate generators; the model illustrates the latter arrangement.
What changes in practice
It obtains additional electricity from heat that would otherwise be discarded. More equipment, water treatment and steam-system controls accompany that gain in electrical efficiency.
Reciprocating gas engine
Fuel burns inside cylinders, pushing pistons connected to a crankshaft and generator. Many natural-gas engines use spark ignition; other designs use a small pilot fuel charge. A station can operate several engine-generator sets, starting or stopping units as the required electrical output changes.
What changes in practice
Modular units can follow changing demand while keeping operating engines usefully loaded. Exhaust and engine-cooling heat can also serve a nearby heat customer.
Gas combined heat and power
A turbine or engine produces electricity while heat exchangers recover energy for steam, hot water or an industrial process. CHP describes this useful heat supply, rather than one particular engine. The recovered heat must reach a real consumer instead of simply being rejected to the surroundings.
What changes in practice
The useful output includes both heat and electricity. Performance depends on matching the plant to the customer’s heat demand as well as its electrical needs.
Worth knowing
- Combined-cycle plants are among the most efficient fossil-fuel plants.
- Open-cycle gas turbines skip the steam stage: less efficient, but they start quickly for peak demand.
- Burning gas emits carbon dioxide; methane leaks upstream add to its climate impact.
See real examples
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Show on the mapRelated answers
Textbook references
Suggested technical background for this topic. These books are further reading, not proof that every explanation was checked against every edition. See the full bibliography and review scope.
- Combined-Cycle Gas & Steam Turbine Power PlantsGas turbines, heat-recovery steam generators and combined-cycle performance.
- Thermodynamics: An Engineering ApproachBrayton and combined Brayton–Rankine cycle thermodynamics.
Sources
- EIA: Use of natural gas ↗
- US DOE: Gas turbines and combined-cycle heat recovery ↗
- Kehlhofer et al.: checked publisher sample ↗
- EIA: How electricity is generated ↗
Cutaways reveal enclosed equipment. Layouts, dimensions, materials and animation speeds are illustrative; this is an educational model, not a plant design. Its fixed-case energy balance is not a time-domain combustion, steam-system or safety simulation.