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Staged biomass pyrogasification plant to grid-injected synthetic methane

Biomass gasification, methanation and grid injection: levelised cost of methane in EUR/MWh PCS from the GoBiGas section costs (Thunman et al. 2019) scaled on fuel input, yearly MWh PCS and Nm3, fuel-to-methane efficiency by reference case, dry feed and energy losses.

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Open Jack

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  • CurrencyEUR 2014
  • Battery limitfully financed
  • 56 documented assumptions
  • Updated27 Oct 2026

Mass and energy balance

What the asset draws and delivers for the case and load you choose.

Reference case

capacity factor: 91.3 %

Full-load hours a year. 8,000 h is the GoBiGas goal and the Chalmers reference; GRTgaz/ATEE (2023) give 7,500 to 8,000 h for French pyrogasification projects.

Flows

  • In: Biomass (dry)—
  • In: Purchased electricity—

Asset

Biomass pyrogasification to grid-injected synthetic methane (GoBiGas-type indirect gasifier)

  • Out: Synthetic methane (grid-injected, HHV)—

Annual quantities at the current usage.

Biomass power entering the plant, on the dry LHV basis that GoBiGas efficiencies use; the capacity the catalogue binds on. The cost law of Thunman et al. (2019) is scaled on this input from a 28,571 kW reference (20 MW of methane at 70 %). The authors defend 20-500 MW of product, so the slider stops at 30 MW of fuel: the method is NOT valid for 0.5-3.5 MW units of the Syncraft or GAYA scale.

Methane output (HHV)
— kW
Methane flow
— Nm3/h
Dry feed rate
— t/h

CAPEX

Specific cost at this size, what backs it, and how it behaves with scale.

Specific CAPEX at this size

—

Reference size 28,571 kW

Thunman 2019, Table 4 (derived)

Model value: the GoBiGas section costs scaled to your fuel input. Customized: your own quote per kW of fuel input, used as is at every size; the value is then no longer sourced.

Specific CAPEX by fuel thermal input (dry LHV)

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  1. Ex-factory
  2. Installed
  3. Fully financed· this figure
CAPEX at the battery limit—

Included

  • Equipment and installation
  • Indirect and owner's costs
  • Contingency

Not included

  • Nothing

Added at project level

  • Nothing: project mode uses the figure as is

Project figures

Values passed to project mode when this asset is added to a project.

Concept sketch, not to scale · drag to rotate

Biomass (dry) in
—
Purchased electricity in
—
Synthetic methane (grid-injected, HHV) outMain product
—
CAPEX to the battery limit
—
Fixed O&M
—
Variable O&M, excluding feedstocks
—
Asset lifetime
20 years

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Levelised cost of methane (HHV)

A standalone indicator for a quick read. Project mode recomputes it for the whole system.

—

  • LCOM: capital—
  • LCOM: development—
  • LCOM: fixed O&M—
  • LCOM: consumables—
  • LCOM: fuel—
  • LCOM: purchased electricity—

Linked to the balance above

capacity factor: 91.3 %

Full-load hours a year. 8,000 h is the GoBiGas goal and the Chalmers reference; GRTgaz/ATEE (2023) give 7,500 to 8,000 h for French pyrogasification projects.

Price per MWh of fuel input. Default 18.7 EUR/MWh, the Chalmers forest residue price (170 SEK/MWh at 9.1 SEK/EUR). That price is quoted on the as-received LHV at 45 % moisture while this calculator counts fuel on the dry LHV basis: applied as is it overstates the fuel bill by roughly a tenth. The slider starts at 10 EUR/MWh: cheaper fuels such as gate-fee waste wood are outside the sourced cost case.

Share of the plant's own electricity (about 0.10 MWh per MWh of methane, mostly compression) made on site. 100 % is the Chalmers reference, whose steam cycle makes the plant self-sufficient. 0 % buys it all from the grid; the steam-cycle investment stays in the CAPEX, so that end is conservative.

Price of purchased electricity. Default 189.9 EUR/MWh, the EU-average non-household price excluding VAT in the second half of 2024 (Eurostat), not a France-specific figure. Has no effect at 100 % self-supply.

Interest rate of the capital recovery factor. Default 5 %, the Chalmers reference. A zero rate is accepted (CRF = 1/n).

Economic lifetime of the plant. Default 20 years, the Chalmers reference.

Levelised cost of methane (HHV) by operating hours at full load

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Benchmarks

This model's figures against published references and reference cases.

Levelised cost of methane (HHV), EUR/MWh

90 Published reference

120 Published reference

Levelised cost of methane (LHV), EUR/MWh

65.5 Published reference

142.9 Published reference

Reference cases at this size and usage

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All results

Every model output at the current settings, grouped, with the sensitivity charts.

53 outputs · 5 groups · 18 also shown above, dimmed

Levelised cost

13
Levelised cost of methane (HHV)
ComputingEUR/MWh
Total investment
ComputingEUR
LCOM: capital
ComputingEUR/MWh
LCOM: development
ComputingEUR/MWh
LCOM: fixed O&M
ComputingEUR/MWh
LCOM: consumables
ComputingEUR/MWh
LCOM: fuel
ComputingEUR/MWh
LCOM: purchased electricity
ComputingEUR/MWh
Levelised cost of methane (LHV)
ComputingEUR/MWh
Levelised cost per Nm3
ComputingEUR/Nm3
Capital share of LCOM
Computing%
Fuel share of LCOM
Computing%
Chalmers reference fuel price
ComputingEUR/MWh

Size and CAPEX

8
Specific CAPEX
ComputingEUR/kW
Model specific CAPEX
ComputingEUR/kW
CAPEX: reactor systems
ComputingEUR
CAPEX: auxiliaries and project
ComputingEUR
CAPEX: steam cycle and drying
ComputingEUR
CAPEX per kW of methane
ComputingEUR/kW
Gap to the single-exponent law
Computing%
Development cost
ComputingEUR

Energy balance

15
Overall efficiency, fuel to methane
Computing%
Cold gas efficiency
Computing%
Efficiency gap to the 70 % design
Computing%
Product gas (cold gas) power
ComputingkW
Methane output (LHV)
ComputingkW
Methane output (HHV)
ComputingkW
Methane flow
ComputingNm3/h
Dry feed rate
Computingt/h
Annual dry feed
Computingt/yr
Specific fuel consumption
ComputingMWh/MWh
Specific feed consumption
Computingkg/Nm3
Gasification losses
ComputingMWh/yr
Cleaning and methanation losses
ComputingMWh/yr
Heat and losses
ComputingMWh/yr
Biochar, staged-thermolysis reference
Computingt/yr

Production and electricity

9
Full-load hours
Computingh/year
Capacity factor
Computing%
Annual methane production (HHV)
ComputingMWh/yr
Annual methane production (LHV)
ComputingMWh/yr
Annual methane volume
ComputingNm3/yr
Annual fuel input
ComputingMWh/yr
Plant electricity use
ComputingMWh/yr
Plant electricity demand
ComputingMW
Purchased electricity
ComputingMWh/yr

Finance and yearly costs

8
Capital recovery factor
Computing1/yr
Annualised capital
ComputingEUR/yr
Fixed O&M
ComputingEUR/yr
Personnel
ComputingEUR/yr
Maintenance
ComputingEUR/yr
Consumables
ComputingEUR/yr
Fuel cost
ComputingEUR/yr
Total yearly cost
ComputingEUR/yr

Sensitivities

6 charts
LCOM components vs operating hours

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LCOM components by reference case

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Specific CAPEX and LCOM vs fuel input

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LCOM vs fuel price

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Where the fuel energy goes, by reference case

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LCOM vs electricity self-supply

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Sources

56 documented assumptions · 9 sources

About

Calculator context

Plant that gasifies dry biomass (forest residues, wood pellets, class B wood) in a gasifier where combustion is decoupled from gasification, cleans the product gas, methanates it catalytically and upgrades it to grid-injection specification. The calculator gives the levelised cost of the injected methane in EUR/MWh on the HHV (PCS) basis used in France, split into capital, development, fixed O&M, consumables, fuel and purchased electricity; the yearly methane in MWh PCS and Nm3; the overall fuel-to-methane efficiency; the dry feed tonnage; the investment by process section; and where the fuel energy is lost. The size input is the fuel thermal input in kW (dry LHV), the capacity the catalogue binds on.

Method. The cost model is that of Thunman et al. (2019, Energy Sci Eng 7:217-229), built on the investment and operating costs actually spent on the 20 MW GoBiGas plant in Gothenburg. Each of the three process sections (reactor systems, auxiliary equipment and project costs, steam cycle with fuel handling and drying) and each fixed cost line is scaled with its own factor from Table 4. Following the authors' closing note, scaling is done on thermal input, from a 28,571 kW reference (20 MW of methane at the 70 % design efficiency). As a reproduction check, not a validation, the 70 % case at that reference size gives about 146 EUR/MWh LHV against 143 in their Table 5, and about 68 against 65.5 at 200 MW of methane.

Reference cases. Three cases set the gasifier's cold gas efficiency, with the same 86 % downstream chain: the GoBiGas operation on dried bark (cold gas 65 %, 55.9 % overall, the default), the best GoBiGas run on wood pellets (63 %) and the Chalmers 70 % design target, judged feasible but not demonstrated. At the defaults (36 MW of fuel, 8,000 h, 5 %, 20 years, 18.7 EUR/MWh fuel, electricity made on site) the plant injects about 178,900 MWh PCS a year, some 16.7 million Nm3, from about 55,300 t of dry feed, for about 170 MEUR of investment and a levelised cost of about 148 EUR/MWh PCS.

Limits. GoBiGas is a dual fluidised bed indirect gasifier, not Novea-type staged pyrolysis; it burns its char internally and exports no biochar, so the biochar figure shown is a staged-thermolysis reference only. Costs are 2011-2014 SEK at 9.1 SEK/EUR, with no escalation. The cost data are defended for 20 to 500 MW of methane: the method is not valid for the 0.5 to 3.5 MW units of the Syncraft or GAYA scale, and below about 28 MW of fuel it diverges from French developer claims of 90 to 120 EUR/MWh PCS. No heat or char revenue is credited.

Model

119 variables — inputs, calculations and outputs, with their dependencies.

119 variables shown of 119
VariableValueUnitDepends on
36000kW—
8000h/year—
1——
0——
4500EUR/kW—
18.7EUR/MWh—
100%—
189.9EUR/MWh—
5%—
20years—
VariableFormulaUnitDepends on
if((<=)+(<=)+(>)+(<)+(>)+(<)+(>)+(<=)+(<)+(<)+(<)+(>)+(<)+(>)+(<)>,,)bool
*ratio
/ratio
++EUR
*/*^EUR
/EUR/yr
**MWh/yr
*/*^EUR/yr
*EUR/yr
VariableFormulaUnitDepends on
min(,)h/year
/*%
if(==,,if(==,/*,/*))%
**%
-%
**kW
**kW
/kW
/Nm3/h
**MWh/yr
**MWh/yr
**MWh/yr
*/Nm3/yr
/(/)/t/h
*t/yr
/max(,)MWh/MWh
*/max(,)kg/Nm3
*MWh/yr
/max(,)MW
*(-*)MWh/yr
*(-*)MWh/yr
**-MWh/yr
++MWh/yr
**t/yr
*/*^EUR
*/*^EUR
*/*^EUR
/max(,)EUR/kW
if(>=,,clamp(,,))EUR/kW
*EUR
/max(,)EUR/kW
(/max(,)-)*%
**EUR
if(<,/,(*(+)^)/max((+)^-,))1/yr
*EUR/yr
*/*^EUR/yr
*/*^EUR/yr
++EUR/yr
/*EUR/yr
*EUR/yr
+++++EUR/yr
/max(,)EUR/MWh
/max(,)EUR/MWh
/max(,)EUR/MWh
/max(,)EUR/MWh
/max(,)EUR/MWh
/max(,)EUR/MWh
+++++EUR/MWh
/max(,)EUR/MWh
/max(,)EUR/Nm3
(+)/max(,)*%
/max(,)*%
/EUR/MWh

Assumptions

56 assumptions used in the calculations

  • Lower limit in the input guards.

    Market range Exact by definition.

    0
    Numerical constant

  • Unit multiplier in the CRF, the guards and the Customized switch.

    Market range Exact by definition.

    1
    Numerical constant

  • Protects divisions against a zero denominator.

    Market range Exact by definition.

    0
    Numerical constant

  • Converts a percent into a fraction.

    Market range Exact by definition.

    0.01
    Numerical constant

  • Converts a fraction into a percent; also the upper guard of percent inputs.

    Market range Exact by definition.

    100
    Numerical constant

  • Hours in a non-leap year: upper limit of the operating hours and basis of the capacity factor.

    Market range Exact by definition.

    8760h/year
    Numerical constant

  • kWh to MWh.

    Market range Exact by definition.

    0.001
    Numerical constant

  • MWh to kWh.

    Market range Exact by definition.

    1000
    Numerical constant

  • Converts the feed heating value from MJ/kg to kWh/kg.

    Market range Exact by definition.

    3.6MJ/kWh
    Numerical constant

  • Kilograms per tonne.

    Market range Exact by definition.

    1000kg/t
    Numerical constant

  • Million SEK to SEK.

    Market range Exact by definition.

    1000000
    Numerical constant

  • Identifier of the reference case 'GoBiGas demonstrated, dried bark and forest residues'.

    Market range Not applicable.

    1
    Selector identifier

  • Identifier of the reference case 'GoBiGas best measured, wood pellets'.

    Market range Not applicable.

    2
    Selector identifier

  • Identifier of the reference case 'Chalmers reference plant, 70 % design efficiency'.

    Market range Not applicable.

    3
    Selector identifier

  • Reference fuel input of the cost scaling: 20 MW of biomethane at the 70 % design efficiency (20,000 / 0.70). Following Thunman et al.'s own note, every section is scaled on thermal input, not on product.

    Market range No independent range cited.

    28571kW
    Thunman 2019, Table 5 / p.228 (derived)

  • Biomethane output of the GoBiGas reference plant, basis of the reference operating costs.

    Market range No independent range cited.

    20000kW
    Thunman 2019, Table 4

  • Design biomass-to-methane efficiency of the reference plant (LHV, dry part of the biomass); used as the yardstick of the efficiency penalty.

    Market range No independent range cited.

    70%
    Thunman 2019, p.218, 224

  • Full-load hours on which the reference operating costs are expressed per MWh.

    Market range No independent range cited.

    8000h/year
    Thunman 2019, Table 4

  • Investment of the reactor systems (gasifier, methanation) at the reference size.

    Market range No independent range cited.

    238MSEK
    Thunman 2019, Table 4

  • Investment of the auxiliary equipment and project costs at the reference size (GoBiGas actual 1141 MSEK, reference plant 955 MSEK).

    Market range No independent range cited.

    955MSEK
    Thunman 2019, Table 4

  • Investment of the steam cycle, external fuel handling and drying at the reference size.

    Market range No independent range cited.

    182MSEK
    Thunman 2019, Table 4

  • Total reference investment, the sum of the three sections; basis of the single-exponent cross-check.

    Market range No independent range cited.

    1375MSEK
    Thunman 2019, Table 4

  • Scale factor of the reactor systems.

    Market range No independent range cited.

    0.68
    Thunman 2019, Table 4

  • Scale factor of the auxiliary equipment and project costs.

    Market range No independent range cited.

    0.44
    Thunman 2019, Table 4

  • Scale factor of the steam cycle, fuel handling and drying.

    Market range No independent range cited.

    0.67
    Thunman 2019, Table 4

  • Single equivalent exponent of the plant: the cost-weighted mean of the three Table 4 section factors at the reference size, (238 x 0.68 + 955 x 0.44 + 182 x 0.67) / 1375 = 0.512 (calculated). The model itself scales each section with its own factor; this exponent is what the page shows as the plant's scale law, and the cross-check output gives the gap between the two (under 4 % over the slider).

    Market range Section factors 0.44-0.68 in the source.

    0.512
    Thunman 2019, Table 4 (derived)

  • Exchange rate used to convert all Chalmers costs; the investment was spent 2011-2014.

    Market range No independent range cited.

    9.1SEK/EUR
    Thunman 2019, p.220

  • Safety floor of the specific CAPEX clamp, far below the model's lowest value on the slider (about 1,600 EUR/kW at 350 MW): it never binds inside the declared domain (checked at the slider ends).

    Market range Not applicable.

    500EUR/kW
    Numerical guard

  • Safety ceiling of the specific CAPEX clamp, far above the model's highest value on the slider (about 5,200 EUR/kW at 30 MW): it never binds inside the declared domain (checked at the slider ends).

    Market range Not applicable.

    20000EUR/kW
    Numerical guard

  • Personnel cost of the reference plant per MWh of biomethane at 20 MW and 8000 h; turned into a yearly amount and scaled with SF 0.10.

    Market range No independent range cited.

    181SEK/MWh
    Thunman 2019, Table 4

  • Maintenance cost of the reference plant, scaled with SF 0.67.

    Market range No independent range cited.

    89SEK/MWh
    Thunman 2019, Table 4

  • Other fixed costs of the reference plant, scaled with SF 0.67.

    Market range No independent range cited.

    26.5SEK/MWh
    Thunman 2019, Table 4

  • Consumables (catalysts, chemicals, bed material) per MWh of biomethane LHV; SF 1.00 in the source, so proportional to output (about 6.05 EUR/MWh).

    Market range No independent range cited.

    55.1SEK/MWh
    Thunman 2019, Table 4

  • Scale factor of personnel cost.

    Market range No independent range cited.

    0.1
    Thunman 2019, Table 4

  • Scale factor of maintenance cost.

    Market range No independent range cited.

    0.67
    Thunman 2019, Table 4

  • Scale factor of other fixed costs.

    Market range No independent range cited.

    0.67
    Thunman 2019, Table 4

  • Development-related cost, as a share of the investment spread over the economic lifetime (Chalmers theta_dev), undiscounted.

    Market range No independent range cited.

    10%
    Thunman 2019, p.223

  • Cold gas efficiency of the GoBiGas gasifier on dried bark or forest residues (chemical energy of the product gas over fuel LHV, dry basis).

    Market range No independent range cited.

    65%
    GoBiGas report 2018, p.38

  • Efficiency of the gas cleaning, methanation and upgrading chain from cold gas to grid-spec methane, held the same in the three cases.

    Market range No independent range cited.

    86%
    GoBiGas report 2018, p.38 (derived)

  • Best measured biomass-to-methane efficiency at GoBiGas (wood pellets, LHV daf). The case's cold gas efficiency is backed out with the 86 % chain.

    63%
    GoBiGas report 2018, Table 3.3

  • Biomass-to-methane efficiency judged technically feasible, the design basis of the Chalmers reference plant. Not demonstrated.

    70%
    GoBiGas report 2018; Thunman 2019

  • Electricity used by the plant (mainly compression) per MWh of methane LHV.

    Market range About 0.095-0.11 from the measured range.

    0.1MWh/MWh
    GoBiGas report 2018, Table 3.5 (derived)

  • LHV / HHV ratio of natural gas, used to express methane on the HHV (PCS) basis of French grid injection.

    Market range 0.90 for methane-rich gas.

    0.9
    ATEE SQ2A 2024

  • Minimum HHV of H-gas accepted for injection, used to convert MWh PCS into Nm3; the volume is therefore an upper estimate (a richer gas gives fewer Nm3).

    10.7kWh/Nm3
    GRTgaz biomethane contract

  • LHV of the dry feed (wood waste), used to turn the fuel input into tonnes of dry feed.

    Market range No independent range cited.

    18.76MJ/kg
    ATEE Expobiogaz 2023, p.34

  • Biochar mass yield of a staged thermolysis plant (HYNOCA, hydrogen configuration), used only for the reference output: GoBiGas burns its char internally and exports none.

    Market range No independent range cited.

    15.7%
    Haffner Energy 2023 (derived)

  • Forest residue price of the Chalmers reference case, shown converted as a reference next to the fuel price input.

    Market range No independent range cited.

    170SEK/MWh
    Thunman 2019, Table 4-5

  • Chalmers production cost of the 20 MW reference plant (70 %, 8000 h, 5 %, 20 years), on the LHV basis: 1300 SEK/MWh / 9.1. Compare with the LHV output in case 3 near 28.6 MW of fuel.

    Market range See rationale.

    142.9EUR/MWh
    Published reference

  • Chalmers production cost at 200 MW of biomethane (about 286 MW of fuel), LHV basis: 596 SEK/MWh / 9.1.

    Market range See rationale.

    65.5EUR/MWh
    Published reference

  • Low end of French developers' claimed price for injectable synthetic methane (HHV basis, 2018 euros) at 2-20 MW of methane, a smaller scale than this calculator; a claim, not an audited cost.

    Market range See rationale.

    90EUR/MWh
    Published reference

  • High end of the same claim range, also given by the ATEE pyrogasification club.

    Market range See rationale.

    120EUR/MWh
    Published reference

  • Method: Thunman et al. (2019) Table 1 eq. 1-11 with the GoBiGas section costs of Table 4, each section scaled on thermal input with its own factor. Reproduction check (not a validation): case 3 at 28,571 kW, 8000 h, 5 %, 20 years and 18.7 EUR/MWh fuel gives about 146 EUR/MWh LHV against 143 in Table 5.

    Market range Not applicable.

    —
    Model scope

  • Scope: GoBiGas is a dual fluidised bed indirect gasifier. It decouples combustion from gasification but it is not Novea-type staged pyrolysis; staged plants are costed here with DFB data, which no source lets us correct.

    Market range Not applicable.

    —
    Model scope

  • Scope: the cost scaling is defended for 20-500 MW of product. Below about 28 MW of fuel it is an extrapolation that diverges strongly from French developer claims (90-120 EUR/MWh PCS at 2-20 MW of methane); it is not valid for 0.5-3.5 MW units.

    Market range Not applicable.

    —
    Model scope

  • Cost basis: SEK spent 2011-2014 converted at 9.1 SEK/EUR with no escalation index; the electricity price default is 2024. Read the LCOM as early-2010s euros: an escalation to today's prices is a known limitation.

    Market range Not applicable.

    —
    Model scope

  • No revenue is credited for heat or char. GoBiGas burns its char internally, so there is no biochar export; the staged-thermolysis biochar output is a reference only.

    Market range Not applicable.

    —
    Model scope