How a biomass CHP plant works
One fuel supply, two useful outputs. Follow solid biomass through a grate-fired boiler and back-pressure steam turbine: a generator exports electricity while turbine exhaust heats a separate district-water loop. CHP means combined heat and power—not a type of fuel.
In 60 seconds: how it works
A biomass plant burns wood or other organic waste to make steam. The steam makes electricity and its leftover heat can also warm buildings.
- Wood chips or other solid biomass fuel are burned on a grate inside a boiler.
- The heat turns water in the boiler into steam.
- The steam spins a turbine connected to a generator, which makes electricity.
- The steam leaving the turbine is still hot, so it warms water for a district heating network through a heat exchanger.
- The smoke is cleaned before it leaves the chimney, and the ash is removed.
- 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.
Explore the equipment in 3D
Rotate equipment, follow energy flows and inspect each component. Read the steps below at any time.
Choose a step to read the process. Activate the 3D model or start a guided tour to use the animation controls.
Solid-biomass grate-fired drum boiler and heat-led back-pressure CHP turbine. Original crane, boiler, turbine, generator and heat-exchanger cutaways. Nominal 5 m/unit, enlarged internals and compressed equipment spacing are illustrative, not construction dimensions. One bounded fixed-state heat-demand calculation is not a calibrated part-load or combustion/transient design. 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
- Energy in biomass
- Fuel preparation
- Combustion heat
- Steam-turbine shaft
- Electricity + useful heat
Bioenergy starts with organic material: wood residues, agricultural by-products, food waste or other biological feedstocks. There is no single machine that suits them all. Dry solid fuels can supply a boiler, while wet organic wastes can be digested to produce a combustible gas. In the model, a grate-fired boiler produces steam for a turbine-generator. The generator converts shaft power into electricity; it is not the fuel itself that flows into the electrical network.
The illustrated back-pressure turbine also supplies useful heat. Steam leaving the turbine transfers heat to a separate district-water loop, then its condensate returns to the feedwater system. This ties operation to a heat customer as well as electricity demand. Combustion still releases carbon dioxide and air pollutants, and ash needs management. Calling a fuel renewable does not mean its exhaust is emission-free. Mixed municipal waste also contains fossil-derived material, so a waste-burning station’s entire output should not automatically be labelled bioenergy.
Follow the power. Keep the heat.
Simple explanation. Biomass burns on a moving grate. Heat makes steam in the boiler, and expanding steam turns a turbine and generator. Instead of expanding all the way to a vacuum waste-heat condenser, the turbine exhaust remains hot enough to serve a heat customer. [B1] [B6]
Two separate loops. Steam condenses outside exchanger tubes, then returns to the boiler. District water flows inside the tubes, warms, supplies the customer and returns. A metal wall transfers heat without mixing the fluids. [B3]
No demand, no hidden sink. This heat-led example reduces fuel and steam when heat demand falls. Zero demand isolates the plant. Other CHP arrangements can use extraction, storage or an explicitly engineered alternate heat sink; they are not silently added here. [B1] [B6]
Selected: Plant overview. Diagram outlines and the 3D highlight share the same selection.
Look inside: fuel, steam and machinery
The grab closes around fuel, raises its load clear of the hopper, travels, lowers and releases before returning. Hoist ropes follow the trolley and grab. The ram and alternating moving/fixed grate lanes explain feeding. Along the bed, drying precedes volatile release and char burnout, leaving ash; these zones overlap in real combustion. Primary air comes through the bed, and secondary air supports gas burnout above it. The sequence is conceptual—not a prediction of residence time, fire temperature, fuel throughput or crane capacity. [B7]
The economiser preheats feedwater. Heated water-wall risers carry a mixture back to the drum; unheated downcomers provide liquid return. Drum internals separate steam before the superheater raises its temperature. The turbine rotor and generator rotor turn together; diaphragms, housings, stator and bearings remain fixed. The cutaways enlarge internals; the visible drum level is not steam quality. Nominal scale is 5 metres per model unit, with compressed equipment spacing and simplified supports—not stress, tube sizing, lift capacity or standards approval. [B2]
Engineering details: one heat-led steady-state model
Specific enthalpy h includes flow work, in joules per kilogram (J/kg). Specific entropy s is in J/(kg·K), with K meaning kelvin. ṁ means mass flow in kg/s; Q̇ means heat-transfer rate in watts (W); P means power in W here. Lowercase p denotes absolute pressure in pascals (Pa). η denotes a dimensionless efficiency. Subscripts f/g mean saturated liquid/vapour; in/out mean turbine inlet/exhaust; an extra s denotes an ideal constant-entropy reference. [B3] [B5]
Steam quality x is vapour mass fraction. T is temperature; cp is specific heat capacity; v is liquid specific volume. Δ means a change, and UCHP means combined energy utilisation. MPa = megapascal (one million Pa); kJ = kilojoule (one thousand J); MJ = megajoule (one million J).
xout,s = (sin − sf)/(sg − sf); hout,s = hf + xout,s(hg − hf)
hout = hin − ηt(hin − hout,s); Pshaft = ṁsteam(hin − hout)
Steam quality x is vapour mass fraction, not a volume fraction. Main steam: 4 MPa absolute / 400 °C, h = 3214.5 kJ/kg, s = 6.7714 kJ/(kg·K). Exhaust: 0.20 MPa, condensing at 120.210 °C; hf = 504.70 and hg = 2706.2 kJ/kg. Turbine efficiency ηt = 0.80 is illustrative. Actual exhaust is slightly wet (x ≈ 0.99536); it is not a fabricated superheated state. Lost ideal work stays in exhaust enthalpy and is not deducted again. A real turbine requires its own moisture limits and performance data. [B3] [B5]
Q̇useful = ṁsteam(hout − hf) = ṁwater cp(Tsupply − Treturn)
T denotes temperature; cp is specific heat capacity, assumed constant at 4180 J/(kg·K) for liquid district water. Supply/return are 90/60 °C in a separate loop at an illustrative 0.30 MPa absolute pressure, not a calculated pressure profile. The constant-cp formula describes sensible heating of liquid water only. Steam condensation uses enthalpy differences, not that formula. Steam temperature exceeds supply temperature; exchanger area and temperature profiles are not sized. No distribution heat loss, leakage or district hydraulic head is solved. [B3]
Δhpump ≈ v Δp / ηpump; hfeed = hf + Δhpump; Q̇boiler = ṁsteam(hin − hfeed)
v is liquid specific volume, 0.00106052 m³/kg at the selected exhaust row; Δp is the 3.8 MPa pressure rise. The constant-volume feed-pump approximation uses ηpump = 0.75. Fluid work is retained in feedwater; electrical pump consumption is fluid work divided by illustrative motor efficiency 0.95. Only motor heat is unrecovered separately. Pressure drop and kinetic/potential changes elsewhere are neglected. [B3] [B5]
Pfuel = ṁfuel LHV = Q̇boiler/ηboiler; ηelectric = Pnet/Pfuel; UCHP = (Pnet + Q̇useful)/Pfuel
Net power is grid export after auxiliaries and transformation; UCHP is energy utilisation, not electrical or exergy efficiency. Exergy means work potential relative to an environment: low-temperature heat and electricity do not have equal work potential. Boiler efficiency 0.85, generator efficiency 0.98 and transformer efficiency 0.995 are invented example assumptions. Other auxiliaries use 6% of gross electricity, including district circulation, fans and fuel handling. Their energy is lumped as unrecovered outside the useful-heat boundary, not added to the district-water heat equation. This is not a pump/network thermal model.
Electrical path: direct three-phase AC export
ns is synchronous speed in revolutions per minute; f is frequency in hertz (Hz); Npoles is total poles, not pole pairs. τ is torque in newton-metres (N·m), and ω is angular speed in radians per second.
ns = 120 f / Npoles = 120 × 50 / 2 = 3000 rpm; τ = Pshaft/ω
ω = 2π ns/60. Positive demand changes torque and power, not synchronous speed. Shaft animation is slowed 100:1 before the viewer speed control. The fixed stator supplies three-phase AC through a breaker and transformer, not a mandatory AC/DC/AC converter. No grid current, voltage, reactive power, excitation or protection settings are calculated. [B4]
Current operating balance
| Measurement boundary | Power |
|---|---|
| Fuel input · as-received LHV | 29.039 MW |
| Boiler heat into working fluid | 24.683 MWth |
| Boiler / stack / other thermal losses (lumped) | 4.356 MW |
| Turbine shaft power | 4.732 MW |
| Gross generator electricity | 4.638 MWe |
| Useful heat at district exchanger | 20.000 MWth |
| Feed-pump work into liquid | 0.049 MW |
| Feed-pump electrical consumption | 0.052 MWe |
| Other electrical auxiliaries | 0.278 MWe |
| Generator heat/loss | 0.095 MW |
| Feed-pump motor heat/loss | 0.003 MW |
| Transformer heat/loss | 0.022 MW |
| Total unrecovered losses | 4.753 MW |
| Net grid export | 4.286 MWe |
Fuel input = useful heat + net export + boiler loss + generator heat + pump-motor heat + other auxiliary heat + transformer heat. Calculated residual: 1.86e-9 W before display rounding. Retained pump fluid work is not a second heat loss.
Net electrical efficiency: 14.761%. CHP energy utilisation: 83.633%. Steam 9.127047 kg/s = condensate 9.127047 kg/s; independent district supply = return 159.489633 kg/s.
| Point | Absolute MPa | h · kJ/kg | Temperature · °C | Phase / quality |
|---|---|---|---|---|
| HX shell condensate → closed receiver | 0.200 | 504.700 | 120.210 | saturated-liquid · x=0.00000 |
| Feed pump → economiser | 4.000 | 510.073 | Not solved | compressed-liquid |
| Economiser outlet / ideal drum saturated-liquid boundary | 4.000 | 1087.500 | 250.354 | saturated-liquid · x=0.00000 |
| Drum separated saturated vapour → superheater | 4.000 | 2800.800 | 250.354 | saturated-vapor · x=1.00000 |
| Main superheated steam → turbine | 4.000 | 3214.500 | 400.000 | superheated-steam |
| Wet back-pressure exhaust → HX shell | 0.200 | 2695.989 | 120.210 | wet-steam · x=0.99536 |
Boiler heat subdivisions: Economiser: liquid heating to ideal saturated-liquid boundary 5.270 MWth; Water walls: evaporation / separated drum vapour 15.637 MWth; Superheater: saturated vapour → main steam 3.776 MWth. Their sum is the one boiler heat input, not extra sources of energy.
Checked example: 20 MWth useful heat
Using the documented states and invented efficiencies: exhaust h = 2695.989326 kJ/kg; ṁsteam = 20,000,000/(2,695,989.326 − 504,700) = 9.127047 kg/s. District water = 20,000,000/[4180 × (90 − 60)] = 159.489633 kg/s. Fuel = 29.039 MW LHV / 12 MJ/kg = 2.419944 kg/s. The same calculation gives 4.638 MWe gross and 4.286 MWe net. [B3] [B5]
29.039 MW fuel = 20.000 MWth useful heat + 4.286 MWe net electricity + 4.753 MW unrecovered losses. Independently tested before rounding; displayed sums can differ by the final digit. This is an illustrative operating point, not a real installation specification.
Fuel basis, ash and emissions
The example fuel has 30% wet-basis moisture: 0.30 kg water per kilogram as received. Its illustrative as-received LHV is 12 MJ/kg, and mineral ash is 2% of that same received mass. Moisture is a fuel descriptor, not another adjustable calculation. Drying consumes heat in the furnace, but the selected as-received LHV already fixes the energy basis: do not subtract moisture evaporation again. A real fuel analysis must establish compatible moisture, calorific value and ash bases. [B7]
At the current setting: fuel moisture 0.7260 kg/s; dry combustible material 1.6456 kg/s; mineral ash 0.0484 kg/s. The invented 80/20 split gives 0.0387 kg/s bottom ash and 0.0097 kg/s fly ash. This is a mineral-ash sub-balance, not the total flue-gas or residue mass: air, volatile chemistry, unburned carbon and added sorbent are not quantified.
Our selected dry alkaline dosing targets acid gases such as hydrogen chloride (HCl) and sulphur dioxide (SO₂). Dirty gas then moves outside-to-inside through fabric bags; dust remains outside, while the clean plenum feeds the ID fan and stack. Top pulses dislodge solids into the filter hopper. Bottom ash leaves the grate separately; filter residue can contain fly ash and spent sorbent. Gas treatment is not a cooling circuit or CO₂ capture. No removal percentage, emission concentration, reagent demand, permit compliance or residue hazard category is inferred. [B8]
Combustion still releases carbon dioxide (CO₂) and other pollutants. Whether biomass use reduces lifecycle climate impact depends on sourcing, land-use change, transport, processing, regrowth and the comparison being made. Separate accounting for biogenic CO₂ does not mean zero stack emissions or automatic carbon neutrality. No lifecycle carbon saving is calculated here. [B7]
Short quiz: follow the boundaries
Does district water enter the steam drum?
No. It stays inside heat-exchanger tubes and its own customer/pump loop. Steam condenses outside the tubes; that condensate returns through the feed pump.
Can this example export electricity with zero heat demand?
No. Its back-pressure exhaust needs the stated heat sink. Zero demand is off. Continued generation would require an explicitly different arrangement, storage or alternate heat-rejection equipment, with its own balance.
Does 83.6% CHP utilisation mean 83.6% electrical efficiency?
No. The default net electrical efficiency is 14.761%. CHP utilisation adds useful heat and net electricity on an energy basis, not an equal-exergy or financial-value basis.
Do the bag filter and stack make biomass carbon-neutral?
No. A fabric filter collects particles; acid-gas dosing is a different mechanism. Neither is the CO₂-capture process absent from this model.
Compare without mixing architectures
Solid biomass: selected grate-fired steam CHP path. Biogas: digester gas commonly fuels an engine with different heat-recovery equipment. Municipal waste: mixed combustible material may include fossil-derived plastics; it is not wholly biomass. See the separately sourced technology variations for those alternatives.
CHP can make better use of fuel when a nearby customer needs heat, but adds a heat network, seasonal coupling, maintenance and combustion/ash-management duties. Extraction-condensing systems can change their heat/power split; this simpler back-pressure case does not have that freedom. No universal heat-to-power ratio, distance threshold or carbon benefit is claimed. [B6] [B7]
Checked bibliography and reading limits
- [B1] Sjaak van Loo and Jaap Koppejan (eds.), The Handbook of Biomass Combustion and Co-firing, Earthscan, 2008. ISBN 9781844072491; DOI 10.4324/9781849773041. Actual lawful preview, §6.3.2 “Rankine cycle”, p.179 checked for back-pressure heat-led CHP. Google’s digital catalogue also lists 2012; other fuel/grate chapters were contents-only further reading, not verified passages.
- [B2] Babcock & Wilcox, Steam: Its Generation and Use, 42nd ed., Gregory L. Tomei (ed.), 2015. ISBN 9780963457028. Actual publisher sample, Chapter 1, pp.1–1 to 1–4 checked for boiling, drum separation and circulation. The biomass/stoker chapters are not in this sample and remain further reading.
- [B3] US DOE, Fundamentals Handbook: Thermodynamics, Heat Transfer, and Fluid Flow, Vol.1, DOE-HDBK-1012/1-92, June 1992. Actual handbook p.21 and pp.79–84: liquid sensible heat, turbine/pump/motor work and exchanger balances. Its “latent heat” wording beside the liquid cp equation is not adopted; condensation is calculated from steam enthalpy.
- [B4] H. H. Woodson and J. R. Melcher, Electromechanical Dynamics, Part I, Wiley, 1968. Actual MIT-hosted Chapter 4, §4.1.8, equation (4.1.95), checked pole pairs and synchronous speed. Our 50 Hz/two-pole selection is illustrative.
- [B5] A. H. Harvey, Thermodynamic Properties of Water: Tabulation from the IAPWS Formulation 1995, NISTIR 5078, 1998. Actual Table 2, pp.12–13 and Table 3, p.47 checked for exact 0.20/4 MPa rows and 4 MPa/400 °C main steam. Pure-water data, not fuel or plant specifications.
- [B6] US EPA, Catalog of CHP Technologies, March 2015, actual Section 4, §4.3.2.4, pp.4–7 to 4–8; §4.4, p.4–9. Back-pressure architecture and turbine-efficiency versus fuel-to-electricity boundaries checked. Historical example ratings/efficiencies are not adopted.
- [B7] IEA Bioenergy Task32: actual combustion stages and grate/air principles; US EPA Biomass CHP Catalog v1.1, 2007, §5.1, mechanism reading only; US EPA Stationary Combustion GHG Inventory Guidance, March 2016, §1.2 p.2, actual carbon caveat checked. No current accounting-rule or numerical lifecycle claim is made.
- [B8] US EPA Fabric Filter—Pulse-Jet Cleaned Type, EPA-452/F-03-025, 2003, pp.3–4 and 2021 Reference Case, Chapter 5, Dry Sorbent Injection p.5–19: actual bag-flow/pulse-cleaning and dry-sorbent mechanisms checked. The latter’s coal/Trona retrofit costs and removal assumptions are not transferred to this educational biomass example.
Named passages checked 3 October 2026. Explanations, diagram and geometry are original. Software/geometry/educational reviews are recorded separately; no independent engineering peer review, construction approval, validated time-domain simulation, emissions permit or safe operating instructions are claimed.
Download the original editable Blender scene. Reproduction, calculation assumptions and actual tests are documented in the project’s Biomass CHP engineering/reference reports.
Inside the engineering
Follow the machinery, the working fluids and the electrical connection.
Mechanical
An articulated grab lifts before traversing and releases into a hopper/ram. Moving grate lanes transport fuel while fixed lanes stay still. Drum separation, water-wall circulation and superheater/economiser tubes explain steam generation. Coaxial turbine/generator shafts rotate inside fixed casings, stators and bearings. Exhaust condenses outside district-water tubes; receiver and feedwater pump close a separate condensate circuit.
Thermal & chemical
Fuel moisture consumes heat during drying. Combustion releases CO₂ and pollutants; ash and flue-gas treatment remain necessary. Lifecycle climate impact depends on feedstock, land use and the supply chain, so biomass is not automatically carbon-neutral.
Electrical
One illustrative two-total-pole/50 Hz synchronous generator runs at 3000 rpm when active, displayed 100:1 slower. Three-phase switchgear and a transformer export net electricity after pumps, other auxiliaries and losses. Separate useful heat and MWe/MWth balances share the same fixed-state model; no heat demand means isolated off without an unmodelled heat dump. Fixed efficiencies give a teaching power-to-heat ratio, not a universal CHP ratio.
Main types and variations
The model shows direct combustion with a back-pressure steam turbine and a heat customer. Other plants use different feedstocks and conversion equipment. CHP is a way to use the heat and can accompany several of these routes; it is not a separate type of biomass fuel.
Direct biomass combustion
Prepared solid biomass burns in a furnace, transferring heat to a boiler and then a steam turbine. Grates and fluidised beds are possible combustion arrangements. The fuel’s condition matters: moisture absorbs heat as it evaporates, while mineral material remains as ash or deposits on heating surfaces.
What changes in practice
It can use suitable solid residues for electricity and heat. Fuel preparation, storage, ash removal and emissions control are part of the plant, not optional accessories.
Anaerobic digestion and biogas
Microorganisms break down organic matter in a sealed digester without free oxygen. The products are biogas, containing methane and carbon dioxide, and a remaining material called digestate. Conditioned biogas can fuel an engine-generator; more extensive treatment can upgrade it for uses that require renewable natural gas.
What changes in practice
This suits wet organic feedstocks that are difficult to burn directly. Gas handling and digestate management are central parts of the process alongside electricity generation.
Biomass gasification
Heat and controlled amounts of oxygen or steam convert solid biomass into synthesis gas instead of fully burning it in a furnace. After suitable cleanup, the gas can supply an engine or turbine. This is a thermal conversion process, distinct from the biological production of digester biogas.
What changes in practice
Gas quality must match the downstream machine. Preparing feedstock and controlling particles, tars and other contaminants are important to reliable operation of a complete power system.
Biomass combined heat and power
A plant supplies useful heat as well as electricity. A steam system may send turbine exhaust or extracted steam to a heat user; a biogas engine may recover exhaust and cooling heat. In either case, a heat exchanger can keep the customer’s water separate from the generating plant’s working fluid.
What changes in practice
Using heat that would otherwise be discarded increases total useful energy recovery. The benefit depends on a nearby customer actually needing that heat when it is available.
Mixed-waste energy recovery
A waste-to-energy furnace burns the combustible portion of municipal waste, often raising steam for electricity and district heating. Paper and food residues are biogenic; petroleum-based plastics are not. Metals and glass do not provide combustion energy, and the plant must manage ash and flue-gas residues.
What changes in practice
Its electricity can contain renewable and nonrenewable contributions. Waste composition matters, so the fuel label alone cannot establish a wholly renewable generation total.
Landfill-gas electricity
Buried organic waste decomposes and releases a gas containing methane and carbon dioxide. A network of wells and pipes collects it. Moisture and contaminants are removed as needed before an engine, turbine or other compatible generator uses the gas to produce electricity and potentially useful heat.
What changes in practice
This recovers fuel from an existing waste site. Gas supply changes over the landfill’s lifetime, so collection performance and changing gas quality constrain generation.
Worth knowing
- Biomass combustion releases CO₂; lifecycle climate benefit depends on feedstock, land use, transport and regrowth times. Renewable does not automatically mean carbon-neutral.
- This heat-led back-pressure example is not an extraction-condensing plant: zero heat demand stops generation. Combined energy utilisation is not electrical or exergy efficiency.
- Some waste-to-energy plants use similar equipment, but mixed municipal waste includes non-renewable material; only its biogenic fraction is biomass.
- Biogas plants usually burn gas in engines rather than using a steam turbine.
See real examples
The atlas includes 1,931 biomass records worldwide.
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.
- Biomass Gasification, Pyrolysis and Torrefaction: Practical Design and TheoryBiomass combustion, gasification and fuel preparation.
- Steam: Its Generation and UseBiomass-fired boilers and combined heat and power.
Sources
- EIA: Biomass explained ↗
- US EPA: Steam turbines and combined heat and power ↗
- Biomass handbook: lawful preview, back-pressure Rankine cycle ↗
- Babcock & Wilcox: Steam 42, Chapter 1 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-state heat-led CHP balance is not a validated part-load, combustion/emissions, pressure-vessel, crane, transient or safety simulation.