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Methanol-to-Olefin (MTO)

Pre-feasibility sizing, mass balance, utilities, plot space, and equipment-purchase CAPEX + OPEX for a methanol conversion unit producing olefin/hydrocarbon intermediates for downstream jet-fuel synthesis.

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alexi

I do low-carbon energy stuff for 10 years & build things I wish existed.

Inputs

Select the methanol conversion route for screening. 1=MTO, 2=MTP, 3=MTG/MTJ-type hydrocarbon intermediate.

Nameplate methanol feed rate into the conversion unit (fresh feed basis).

t/h

min 0 · max 300 · step 1 · t/h

Annual average utilization including downtime (0–100%).

min 0 · max 100 · step 1 · %

Mass yield of methanol to the target intermediate stream (screening aggregate yield including selectivity and losses).

min 0 · max 100 · step 1 · %

Delivered electricity price used for OPEX estimation.

EUR/MWh

min 0 · max 500 · step 1 · EUR/MWh

Price of imported thermal energy (steam/hot oil). Net heat demand may be reduced by offgas heat recovery.

EUR/MWh

min 0 · max 300 · step 1 · EUR/MWh

Price for industrial water used as makeup/utility water (screening).

EUR/m3

min 0 · max 50 · step 0.1 · EUR/m3

Cost of methanol feedstock (fossil or e-methanol). Upstream methanol synthesis is not costed in this unit model.

EUR/t

min 0 · max 2000 · step 5 · EUR/t

Used to compute CRF for annualizing equipment purchase CAPEX.

ratio

min 0 · max 0.3 · step 0.005 · ratio

Amortization period used with the discount rate to annualize CAPEX.

yr

min 1 · max 40 · step 1 · yr

Results

Nominal methanol inlet capacity

Nameplate methanol feed rate to the conversion unit

…t/h

Number of parallel process trains

Based on max practical single-train throughput

…count

Methanol capacity per train

Capacity split evenly across trains

…t/h

Estimated total plot space

Includes integration margin for access, pipe-racks, and maintainability

…m2

Annual methanol inlet

Based on capacity factor and nameplate throughput

…t/yr

Intermediate outlet flow

Desired intermediate stream for downstream jet-fuel synthesis

…t/h

Annual intermediate production

Intermediate production at the specified capacity factor

…t/yr

Reaction/separation water produced

Screening estimate of water byproduct requiring separation/handling

…t/yr

Offgas/light-ends to management

Purge, light hydrocarbons, and non-condensables (screening closure)

…t/yr

Annual electricity consumption

Compression, pumps, separation auxiliaries (screening)

…MWh/yr

Net external heat demand

Gross heat demand minus recoverable offgas energy

…MWh/yr

Total equipment purchase CAPEX

Sum of conditioning, reactor, separation, polishing, and light-gas management (purchase cost only)

…EUR

Equipment CAPEX — methanol conditioning

Feed conditioning, preheat, contaminant management (screening scope)

…EUR

Equipment CAPEX — reactor section

Catalytic reactor(s), quench, primary heat exchange (screening scope)

…EUR

Equipment CAPEX — water separation

Condensation, phase separation, distillation/dehydration (screening scope)

…EUR

Equipment CAPEX — intermediate polishing

Intermediate conditioning for downstream synthesis (screening scope)

…EUR

Equipment CAPEX — light-gas management

Compression/flare/oxidation/recovery interface (screening scope)

…EUR

Annualized CAPEX (equipment purchase)

Equipment purchase cost annualized using CRF (no installation/indirects)

…EUR/yr

Annual fixed O&M cost

Scaled and clamped fraction of equipment purchase CAPEX

…EUR/yr

Annualized catalyst replacement cost

Periodic replacement annualized over catalyst life

…EUR/yr

Annual utilities cost

Electricity + net heat + makeup water

…EUR/yr

Annual methanol feedstock cost

Methanol inlet × methanol price

…EUR/yr

Total annual cost

Annualized CAPEX + O&M + replacement + utilities + methanol

…EUR/yr

Levelized cost of intermediate

Total annual cost divided by annual intermediate production

…EUR/t

Levelized cost (per MWh LHV of intermediate)

Uses assumed intermediate LHV by technology option

…EUR/MWh

Embodied upstream H2 in annual methanol feed (stoichiometric)

Equivalent green H2 that would be required to synthesize the methanol feed from CO2

…t/yr

Embodied upstream CO2 in annual methanol feed (stoichiometric)

Equivalent CO2 that would be required to synthesize the methanol feed

…t/yr

About

Calculator context

Introduction

This calculator screens a methanol-to-intermediates conversion unit that produces methanol-derived olefins or hydrocarbon intermediates suitable for downstream jet-fuel synthesis. It estimates mass flows, utilities (heat/electricity), plot space, major equipment train count, and equipment purchase cost + annual costs using a transparent scaling methodology aligned with pre-feasibility practice.

Key reference frameworks include IEA/IRENA cost/efficiency compilation approaches, and standard chemical engineering power-law scaling and capital recovery factor methods widely used in NREL/IEA-style techno-economic assessments.

Methodology

The model uses the user’s nominal methanol inlet flow (t/h), capacity factor (%), overall yield to desired intermediate (%), and a technology option (MTO/MTP/MTG). Core calculations:

  • Operating hours: OperatingHours = 8760 * (CapacityFactor% * 0.01)
  • Annual methanol feed: MeOH_in_tpy = Capacity_tph * OperatingHours
  • Intermediate production: Intermediate_tph = Capacity_tph * (Yield% * 0.01); Intermediate_tpy = Intermediate_tph * OperatingHours
  • Byproducts (screening mass balance):
    • Water_tph = Capacity_tph * WaterYield_per_tMeOH(tech)
    • Offgas_tph = max(Capacity_tph − Intermediate_tph − Water_tph, 0)
  • Utilities:
    • Electricity_MWh/y = MeOH_in_tpy * kWh_per_tMeOH(tech) / 1000
    • HeatGross_MWh/y = MeOH_in_tpy * Heat_kWh_per_tMeOH(tech) / 1000
    • Offgas heat recovery: HeatNet = max(HeatGross − OffgasEnergy * RecoveryEff, 0)
  • Sizing:
    • Trains: n_units = ceil(Capacity_tph / MaxTrainCapacity_tph)
    • Plot space scales by power law per train and adds an integration margin.
  • Costing:
    • Subsystem equipment purchase CAPEX per train scales: CAPEX = CAPEX_ref * (Capacity_per_train/RefCapacity)^exp, summed across conditioning, reactor, separation, polishing, and light-gas management.
    • CRF: CRF = (r*(1+r)^n)/((1+r)^n−1) (with denominator guard)
    • AnnualizedCAPEX = CAPEX_total * CRF; TotalAnnualCost adds fixed O&M (scaled & clamped), variable O&M, catalyst replacement, utilities, and methanol feedstock.
    • Levelized cost is reported as EUR/t-intermediate and EUR/MWh-LHV.

Applications

  • Project developer (screening): Compare MTO vs MTG options for a given methanol supply and capacity factor; identify net heat import and train count.
  • Process engineer (early concept): Rapidly estimate subsystem equipment purchase CAPEX split and plot space to support layout and packaging decisions.
  • Commercial analyst (pre-FEED): Produce first-pass levelized intermediate cost and test sensitivity to methanol and utility prices.

Model

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

114 variables shown of 114
VariableValueUnitDepends on
1——
50t/h—
90%—
40%—
70EUR/MWh—
30EUR/MWh—
1.5EUR/m3—
350EUR/t—
0.08ratio—
20yr—
VariableFormulaUnitDepends on
if(((<0)+(<0)+(>100)+(<0)+(>100)+(<0)+(<=0)+(<0)+(<0)+(<0)+(<0)+(<1)+(>3))>0,1,0)bool
*0.01—
*h/yr
*h/yr
*0.01—
if(==1,,if(==2,,))t/t
*t/h
max((--),0)t/h
if(==1,,if(==2,,))kWh/t
if(==1,,if(==2,,))kWh/t
*/max(,)MWh/yr
***MWh/yr
*MWh/yr
*m3/yr
*(/max(,))^m2
if(==1,,if(==2,,))—
/max(,)EUR/(t/h)
clamp(,,)EUR/(t/h)
*(/max(,))^—
clamp(,,)—
*EUR/yr
*EUR/yr
*EUR/yr
*EUR/yr
(*(1+)^)/max(((1+)^-1),)—
if(==1,,if(==2,,))MJ/kg
***MWh/yr
VariableFormulaUnitDepends on
t/h
*t/yr
*t/h
*t/yr
*t/yr
*t/yr
*/max(,)MWh/yr
max((-),0)MWh/yr
max(1,ceil(/max(,)))count
/max(,1)t/h
**m2
*(*)*(/max(,))^EUR
*(*)*(/max(,))^EUR
*(*)*(/max(,))^EUR
*(*)*(/max(,))^EUR
*(*)*(/max(,))^EUR
++++EUR
*EUR/yr
*/max(,)EUR/yr
++EUR/yr
*EUR/yr
*EUR/yr
+++++EUR/yr
/max(,)EUR/t
/max(,)EUR/MWh
*t/yr
*t/yr

Assumptions

52 assumptions used in the calculations

  • Prevents division-by-zero and instability in CRF and intensity calculations.

    0.000001
    Modeling convention

  • Converts capacity factor to annual operating hours.

    Market range 365

    365day/yr
    Calendar constant

  • Converts days to hours for annualization.

    Market range 24

    24h/day
    Calendar constant

  • Converts kWh-based intensities to MWh outputs.

    Market range 1000

    1000kWh/MWh
    Unit conversion

  • Mass conversion for LHV and offgas energy calculations.

    Market range 1000

    1000kg/t
    Unit conversion

  • Converts MJ (LHV) to MWh for energy-normalized outputs.

    Market range 0.0002777778

    0.000278MWh/MJ
    Unit conversion

  • Reference single-train methanol throughput used for scaling subsystem CAPEX and plot area.

    50t/h
    Modeling assumption

  • Approximates practical maximum throughput for a single train before parallelization at screening level.

    80t/h
    Engineering heuristic

  • Reference plot space per train at ref capacity, representing unit battery limits without major offsites.

    5000m2
    Engineering heuristic

  • Plot space increases sub-linearly with capacity due to economies of scale.

    0.65
    Scaling assumption

  • Accounts for access, maintainability, pipe-racks, and integration spacing.

    1.25
    Layout margin assumption

  • Represents typical oxygen rejection as water in methanol-to-olefins chemistry.

    0.56t/t
    Stoichiometry-informed screening factor

  • Similar oxygen rejection behavior for methanol-to-propylene/light olefins at screening level.

    0.56t/t
    Stoichiometry-informed screening factor

  • Hydrocarbon-range products and aromatics formation can shift water yield; this is a simplified typical value.

    0.52t/t
    Screening factor

  • Represents auxiliaries (pumps, compression, separation) per tonne methanol processed for MTO screening.

    90kWh/t
    Benchmarking assumption

  • Electricity intensity for MTP-like configurations at screening level.

    95kWh/t
    Benchmarking assumption

  • Slightly higher electricity needs reflecting broader separation/conditioning in MTG/MTJ-type routes.

    110kWh/t
    Benchmarking assumption

  • Represents net imported heat before offgas recovery for separation and conditioning duties.

    300kWh/t
    Benchmarking assumption

  • Gross heat demand screening value for MTP-like configuration.

    320kWh/t
    Benchmarking assumption

  • Higher gross heat demand screening value for MTG/MTJ-like routes due to broader fractionation/polishing.

    420kWh/t
    Benchmarking assumption

  • Represents typical LHV of a light-hydrocarbon-rich offgas stream used for heat recovery screening.

    45MJ/kg
    Screening energy property

  • Fraction of offgas LHV assumed recoverable as useful heat to offset imported heat demand.

    0.45ratio
    Process integration assumption

  • Represents net makeup water for cooling/ancillary uses (not the separated reaction water).

    0.15m3/t
    Utility assumption

  • Covers consumables, routine chemicals, waste handling, and minor variable expenses per tonne methanol processed.

    8EUR/t
    Screening OPEX factor

  • Reference annual fixed O&M fraction of equipment purchase cost (labor, maintenance, overhead).

    0.04ratio
    TEA convention

  • Introduces mild economy-of-scale in fixed O&M fraction with increasing plant capacity.

    -0.05
    Scaling assumption

  • Lower bound prevents unrealistic fixed O&M at very large scale.

    0.02ratio
    Bounded assumption

  • Upper bound prevents unrealistic fixed O&M at very small scale.

    0.08ratio
    Bounded assumption

  • Applies power-law scaling of conditioning equipment purchase cost with capacity per train.

    0.7
    Scaling assumption

  • Reactor systems often scale slightly less favorably due to metallurgy, heat removal, and internals.

    0.75
    Scaling assumption

  • Separation equipment cost scales sub-linearly with capacity due to column sizing and heat exchange economies.

    0.7
    Scaling assumption

  • Intermediate polishing (e.g., dehydration, stabilization) scales sub-linearly with capacity.

    0.7
    Scaling assumption

  • Light-gas management equipment (flare/recovery) often has weaker capacity dependence at screening level.

    0.65
    Scaling assumption

  • Reference equipment purchase cost for conditioning subsystem at ref train capacity.

    12000000EUR
    Reference point (screening)

  • Reference equipment purchase cost for reactor section at ref train capacity.

    35000000EUR
    Reference point (screening)

  • Reference equipment purchase cost for separation and dehydration at ref train capacity.

    20000000EUR
    Reference point (screening)

  • Reference equipment purchase cost for intermediate polishing at ref train capacity.

    8000000EUR
    Reference point (screening)

  • Reference equipment purchase cost for light-gas management at ref train capacity.

    5000000EUR
    Reference point (screening)

  • Relative CAPEX factor for MTO baseline option.

    1
    Screening adjustment

  • Slightly higher CAPEX for MTP-like configuration at screening level.

    1.05
    Screening adjustment

  • Higher CAPEX for MTG/MTJ-like intermediate routes reflecting additional separation/polishing complexity.

    1.15
    Screening adjustment

  • Lower clamp bound for specific CAPEX to avoid unrealistic values from extreme scaling inputs.

    200000EUR/(t/h)
    Bounding assumption

  • Upper clamp bound for specific CAPEX to avoid runaway values at very small scale.

    4000000EUR/(t/h)
    Bounding assumption

  • Represents typical replacement interval for catalytic systems (order-of-magnitude).

    3yr
    Screening assumption

  • Approximates replacement catalyst/adsorbent cost as a fraction of reactor-section equipment cost per replacement event.

    0.12ratio
    Screening assumption

  • Represents LHV of an olefin/hydrocarbon intermediate stream for energy-normalized cost reporting.

    45MJ/kg
    Screening energy property

  • LHV assumption for MTP-like intermediate streams.

    45MJ/kg
    Screening energy property

  • Approximate LHV for gasoline/jet-range hydrocarbon intermediates, consistent with common jet-fuel LHV reporting (~43 MJ/kg).

    43MJ/kg
    Screening energy property

  • From CO2 + 3H2 → CH3OH + H2O: 6 g H2 per 32 g MeOH.

    Market range 0.1875

    0.1875tH2/tMeOH
    Stoichiometry

  • From CO2 + 3H2 → CH3OH + H2O: 44 g CO2 per 32 g MeOH.

    Market range 1.375

    1.375tCO2/tMeOH
    Stoichiometry

  • The water inlet and the water outlet of this unit must not be chained to each other: 'Water makeup' is cooling and ancillary demand, while 'Reaction/separation water' is the oxygenate-laden water separated downstream of the MTO reactor. Closing that loop requires a wastewater treatment step this calculator does not cost.

    Market range Not applicable (chaining rule).

    —
    Chaining doctrine written 2026-09-03 after checking the two water assumptions of this calculator: mto_water_yield_per_t_meoh (0.56 t/t) is the stoichiometric oxygen rejection, and water_makeup_m3_per_t_meoh (0.15 m3/t) is explicitly documented as 'not the separated reaction water'. The two streams were already distinguished; only the rule was missing.

  • The only chainable inlet of this asset is 'Methanol feedstock': the legitimate upstream is a methanol synthesis calculator, and the link coefficient there is the delivered mass ratio, never an arbitrary partial coefficient. Electricity, heat and makeup water are bought utilities, not chained flows.

    Market range Not applicable (chaining rule).

    —
    Chaining doctrine written 2026-09-03. A partial coefficient on a same-commodity link is what produced the absurd LCO of project #27; on this asset the feedstock link is cross-commodity, so the coefficient is a yield, and it must stay one.