Boiler Efficiency Calculator — Fuel-to-Steam (Direct & Indirect Method)

• Steam pressure and condition. The boiler outlet pressure — a gauge reading is converted to absolute by adding the standard atmosphere, 1.01325 bar, before the property lookup — and whether the steam leaves saturated or superheated to a stated temperature. The outlet enthalpy h_s is the IAPWS-IF97 saturated-vapour value at that pressure, or the superheated value at pressure and temperature.
• Feedwater temperature. The water temperature entering the boiler (after the deaerator or economiser). Its enthalpy h_fw is evaluated as compressed liquid at the boiler pressure, so the enthalpy rise h_s − h_fw is exactly the heat the boiler adds per kilogram; the pressure term is worth only about 1 kJ/kg at 10 bar, so saturated-liquid enthalpy at the feedwater temperature gives practically the same answer. Hotter feedwater means less heat per kilogram of steam — which is why an economiser raises efficiency.
• Steam mass flow. The steam actually leaving the boiler. Multiplied by the enthalpy rise it gives the useful output in kW. Blowdown water leaves at saturation temperature without becoming steam, so it is not in this figure — its heat counts as a loss.
• Fuel type and gross calorific value. GCV (the higher heating value, HHV) is the heat released per kilogram including the latent heat of the water vapour formed in combustion. Presets are illustrative typical values; gaseous fuels are stored per normal cubic metre and converted to a mass basis with a typical density (natural gas 38.0 MJ/Nm³ ÷ 0.76 kg/Nm³ = 50.0 MJ/kg — pipeline gas ranges roughly 37–40 MJ/Nm³ and 0.70–0.80 kg/Nm³). Use Custom with the supplier's analysis for a specific fuel.
• Fuel consumption. The fuel mass rate. For gas metered by volume, convert with the same density (Nm³/h × kg/Nm³) before entering it. Fuel energy input = consumption × GCV.
• Boiler thermal efficiency. The direct (input–output) method: η = steam energy output ÷ fuel energy input, on a GCV basis. Heat losses are simply the difference — flue gas, radiation, blowdown and unburnt fuel together — without saying which is which; that split needs the indirect (heat-loss) method.
• CO₂ emissions. The fuel's IPCC default emission factor (natural gas 56.1 g CO₂/MJ, fuel oil 74–77, coal 95–101) is defined per megajoule of net calorific value, so it is applied to the fuel energy divided by the fuel's GCV/NCV ratio (1.11 for natural gas, 1.06 oil, 1.04 coal). Biomass and biogas are shown as zero by the inventory convention that biogenic carbon is counted in the land-use sector, not at the stack. The per-tonne figure divides by the steam flow.
• Fuel comparison table. For a target efficiency you set, the fuel consumption each preset would need to raise the same steam: at equal efficiency, consumption scales with 1/GCV — the starting point of a fuel-switch estimate.

• Direct (input–output) method of ASME PTC 4 / EN 12953-11: efficiency from metered steam and fuel flows. Its accuracy is the metering's — a 2 % error in either flow is a 2 % error in efficiency — and it cannot say where the losses are; the indirect (heat-loss) method is not performed here.
• Gross calorific value (HHV) basis throughout. European practice often quotes efficiency on the net (NCV / LHV) basis, which is higher by GCV/NCV — about 1.11 for natural gas, 1.06 for fuel oil, 1.04 for coal. Compare like with like.
• Steady state with steam flow equal to feedwater flow: there is no blowdown input (continuous or intermittent), so blowdown, safety-valve lifts, soot-blowing steam and level swings are neither credited nor charged — the blowdown heat simply sits inside the reported losses.
• Fuel calorific values and densities are typical preset figures; the supplier's analysis governs for a real fuel, and gas composition (and therefore GCV per Nm³) varies by network and season.
• Superheated steam takes the outlet temperature as given, with no desuperheating spray water — if a spray is fitted, subtract its mass from the steam flow entered; wet steam (dryness below 1) is not modelled and would overstate the output.
• Auxiliary power (fans, feed pumps), fuel preheating and start-up or standby losses are outside the boundary; this is combustion-to-steam efficiency, not the boiler house's.
• CO₂ figures are combustion emissions from the IPCC 2006 default factors, which are defined per MJ of net calorific value and are applied here to the net share of the gross fuel energy — not a lifecycle or upstream figure, and zero for biogenic fuels by convention.

Steam and feedwater enthalpies come from the same IAPWS-IF97 engine as the steam-tables calculator, which reproduces the standard's published verification points; the SimuPipe solver's own accuracy is documented on the validation page.

Method and data sources behind this page:

• ASME PTC 4-2013. Fired Steam Generators — Performance Test Codes — the input–output and heat-loss methods and their measurement requirements.
• EN 12953-11:2003. Shell boilers — Part 11: Acceptance tests; EN 12952-15:2003. Water-tube boilers — Part 15: Acceptance tests — the European acceptance-test procedures and the NCV-basis convention.
• IPCC (2006). Guidelines for National Greenhouse Gas Inventories, Volume 2, Chapter 2, Table 2.2 — default CO₂ emission factors. ipcc-nggip.iges.or.jp — the emission factors per MJ used for the CO₂ figures.
• Spirax Sarco. Steam Engineering Tutorials — Boiler Efficiency and Combustion. spiraxsarco.com — boiler efficiency definitions, typical loss breakdown and the economiser / feedwater effect.
• US DOE, Advanced Manufacturing Office. Steam Tip Sheet #4: Improve Your Boiler's Combustion Efficiency. energy.gov — typical efficiency ranges and the main improvement measures.
• IAPWS R7-97(2012). Revised Release on the IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam. iapws.org — the steam and compressed-liquid enthalpies.