Methanol and Synthetic Fuels from Natural Gas - Gas-to-Liquids Chemistry, Fischer-Tropsch Synthesis, and E-Fuel Techno-Economics

Methanol and Synthetic Fuels from Natural Gas - Gas-to-Liquids Chemistry, Fischer-Tropsch Synthesis, and E-Fuel Techno-Economics

The conversion of natural gas and renewable energy into liquid fuels methanol, synthetic diesel, synthetic aviation fuel, and dimethyl ether represents the petroleum industry's most direct technical pathway to supplying decarbonized energy to sectors that cannot easily be electrified. Aviation, shipping, and heavy road transport collectively account for approximately 30% of global CO2 emissions from energy use, and all three sectors face the same fundamental constraint: the energy density of batteries (200-300 Wh/kg for current lithium-ion technology) is insufficient to power long-distance heavy transport, while hydrogen's low volumetric energy density (even in liquid form at -253°C) creates storage, handling, and infrastructure challenges that are particularly severe for aviation and marine applications. Synthetic liquid fuels produced either from natural gas (blue synthetic fuels, using CCS to manage the CO2 co-product) or from renewable electricity via Power-to-X pathways (green synthetic fuels, also called e-fuels or electrofuels) can use existing fuel distribution infrastructure, existing engines with minimal modification, and existing storage facilities, making them a potentially near-term solution to decarbonizing these hard-to-abate sectors. The petroleum industry's engagement with synthetic fuels is not new: Fischer-Tropsch synthesis has been operated at large commercial scale by Sasol in South Africa since 1955 and by Shell in Bintulu and Pearl (Qatar) for decades. What is new is the pressure to produce these fuels from low-carbon feedstocks at a cost competitive with fossil-derived equivalents, which requires either very cheap natural gas with high-efficiency CCS (blue) or very cheap renewable electricity with high-efficiency electrolysis (green). This guide covers the complete technical and economic framework: the methanol synthesis chemistry that is the foundation of most synthetic fuel pathways, the Fischer-Tropsch process that converts syngas to hydrocarbon fuels, the methanol-to-jet pathway that produces sustainable aviation fuel, and the comparative economics that determine when and where synthetic fuels become commercially viable.

1. Methanol Synthesis: The Foundation of Synthetic Fuel Production

1.1 Methanol Synthesis Chemistry and Reactor Design

Methanol synthesis converts a mixture of CO, CO2, and H2 (synthesis gas or syngas) into methanol over a copper-zinc oxide catalyst at moderate temperature and pressure. The syngas can be derived from natural gas via steam methane reforming or autothermal reforming (for blue methanol) or from electrolysis hydrogen combined with captured CO2 (for green/e-methanol):

Methanol synthesis reactions:
CO hydrogenation: CO + 2H2 → CH3OH    (delta_H = -90.7 kJ/mol, exothermic)
CO2 hydrogenation: CO2 + 3H2 → CH3OH + H2O    (delta_H = -49.5 kJ/mol, exothermic)
Reverse water-gas shift: CO2 + H2 → CO + H2O    (delta_H = +41.2 kJ/mol, endothermic)

Stoichiometric feed composition (module M):
M = (H2 - CO2) / (CO + CO2)
Optimal M for methanol synthesis: 2.0-2.1

Syngas production for green methanol (e-methanol):
H2 from electrolysis: (required H2 per mole CH3OH) = 3 moles H2 per mole CH3OH from CO2
CH3OH molar mass: 32 g/mol
H2 molar mass: 2 g/mol
H2 per kg methanol: 3 x 2/32 = 0.1875 kg H2/kg CH3OH

CO2 per kg methanol: 1 x 44/32 = 1.375 kg CO2/kg CH3OH**

**Annual production target: 100,000 tonnes methanol/year
H2 required: 100,000 x 0.1875 = 18,750 tonnes H2/year**

**CO2 required: 100,000 x 1.375 = 137,500 tonnes CO2/year**

**Electrolysis power for H2 production: 18,750 x 1,000 kg x 55 kWh/kg = 1,031,250,000 kWh = 1,031.3 GWh/year**

**Electrolyzer capacity: at 8,760 hr/year x 0.90 availability:
Required power = 1,031,300 MWh / (8,760 x 0.90) = 1,031,300/7,884 = 130.8 MW electrolyzer capacity**

**Methanol reactor design parameters:
Operating conditions: T = 220-280°C, P = 50-100 bar (typical industrial conditions)
Catalyst: Cu/ZnO/Al2O3 (ICI Low Pressure process, most widely deployed)
Per-pass conversion: 15-25% (low conversion due to equilibrium limitations)
Overall conversion (with recycle): 95-99%

Space velocity and reactor sizing:
Gas hourly space velocity (GHSV): 10,000-15,000 h^-1 (standard industrial)
Reactor temperature control: critical - catalyst deactivates above 280°C (sintering)
Heat management: intercooled multiple reactors OR Linde isothermal reactor (cooling tubes inside reactor bed)

Methanol synthesis equilibrium conversion at 250°C, 80 bar:
K_eq at 250°C (523K) from van't Hoff: K_eq ≈ exp((90,700/(8.314 x 523)) - (90,700/(8.314 x 298) - delta_S/R))
Approximate approach: at 250°C, 80 bar, M = 2.1, per-pass equilibrium conversion ≈ 22% of CO

Recycle ratio required to achieve 97% overall conversion: R = (97% - 22%) / 22% ≈ 3.4 (recycle 3.4 volumes per volume fresh feed)

Compressor duty for recycle: significant energy consumption
Recycle compressor power: approximately 15% of total plant electricity consumption

1.2 Methanol Yield and Energy Efficiency

Overall green methanol energy efficiency calculation:

Energy inputs per tonne methanol produced:
1. Electrolysis (H2 production): 0.1875 t H2 x 55,000 kWh/t = 10,313 kWh/t MeOH**

**2. CO2 capture (from industrial emitter): 1.375 t CO2 x 1,000 kWh/t CO2 (amine capture) = 1,375 kWh/t MeOH**

**3. Methanol synthesis compression + plant power: approximately 250 kWh/t MeOH**

**Total energy input: 10,313 + 1,375 + 250 = 11,938 kWh/t MeOH**

**Energy content of methanol: LHV = 19.9 MJ/kg = 5,528 kWh/t

Overall energy efficiency: 5,528/11,938 = 46.3% (chemical energy stored/electrical energy consumed)**

**This low efficiency is the fundamental challenge for e-methanol economics. Only 46.3% of the input electrical energy ends up as chemical energy in the methanol product. The remaining 53.7% is lost primarily as heat in the electrolysis process and methanol synthesis reactions.

Carbon balance per tonne of methanol:
CO2 consumed (input): 1.375 t CO2
CO2 embedded in methanol (as carbon): methanol = CH3OH → carbon content = 12/32 = 37.5% by mass
Carbon in methanol: 1,000 kg x 0.375 = 375 kg C → as CO2: 375 x 44/12 = 1,375 kg CO2
Net CO2 balance: 1.375 t consumed in synthesis - 1.375 t stored in methanol = 0 net CO2 (if methanol is combusted, CO2 released = CO2 consumed)**

**This demonstrates the carbon neutrality of e-methanol: the CO2 that is emitted when methanol burns was captured from the atmosphere or from industrial emissions before synthesis. If the CO2 source is atmospheric (direct air capture), the cycle is genuinely net-zero. If CO2 source is industrial (cement, steel), the methanol is carbon-neutral only if those industrial emissions would have been emitted anyway (additionality requirement).

2. Fischer-Tropsch Synthesis: Gas-to-Liquids Chemistry

2.1 FT Reaction Chemistry and Product Distribution

Fischer-Tropsch synthesis converts syngas (CO + H2) into a distribution of hydrocarbon products ranging from methane (C1) to heavy waxes (C50+) over iron or cobalt catalysts. The product distribution is described by the Anderson-Schulz-Flory (ASF) model, which predicts the fraction of each carbon number product as a function of a single parameter, the chain growth probability alpha:

Anderson-Schulz-Flory product distribution:
W_n = n x (1-alpha)^2 x alpha^(n-1)

Where:
W_n = weight fraction of product with carbon number n
alpha = chain growth probability (0 to 1)
n = carbon number

Alpha values and product slate:
Low alpha (0.72-0.80): Maximum gasoline (C5-C12) fraction → favors motor gasoline production
Medium alpha (0.85-0.90): Balanced diesel (C13-C22) and gasoline → most commercial FT processes
High alpha (0.92-0.95): Maximum wax (C22+) → selective for wax production then hydrocracking to diesel

Product distribution calculation for alpha = 0.90 (Shell Pearl-type cobalt catalyst):
Methane (C1): W_1 = 1 x (0.10)^2 x 0.90^0 = 0.0100 = 1.0%**

**Gasoline fraction C5-C12 (sum W_5 to W_12):
W_5 = 5 x 0.01 x 0.90^4 = 5 x 0.01 x 0.6561 = 0.03281
W_8 = 8 x 0.01 x 0.90^7 = 8 x 0.01 x 0.4783 = 0.03827
W_10 = 10 x 0.01 x 0.90^9 = 10 x 0.01 x 0.3874 = 0.03874
W_12 = 12 x 0.01 x 0.90^11 = 12 x 0.01 x 0.3138 = 0.03766
Sum C5-C12 ≈ 0.263 = 26.3% gasoline fraction**

**Diesel fraction C13-C22:
W_15 = 15 x 0.01 x 0.90^14 = 15 x 0.01 x 0.2288 = 0.03432
W_20 = 20 x 0.01 x 0.90^19 = 20 x 0.01 x 0.1351 = 0.02703
Sum C13-C22 ≈ 0.265 = 26.5% diesel fraction**

**Wax fraction C23+:
Remainder = 1 - CH4(1%) - C2-C4(5%) - C5-C12(26.3%) - C13-C22(26.5%) = 1 - 0.588 = 41.2% wax**

**In a commercial GTL plant, the wax is hydrocracked to additional diesel:
Overall diesel yield with hydrocracking: approximately 70-75% of total liquid product
Methane + light gas byproduct: 6-8% (typically used as fuel gas)

Syngas requirement per barrel of FT liquid:
FT reaction stoichiometry: CO + 2H2 → -CH2- + H2O (for chain growth)
Per barrel (0.159 m3) of FT product (density ~800 kg/m3 = 127 kg/bbl):
Carbon content: 127 x 0.856 (average C fraction) = 108.7 kg C per bbl
CO required: 108.7 x 28/12 = 253.6 kg CO per bbl
H2 required: 108.7 x 2/12 x 2 = 36.2 kg H2 per bbl (simplified)

More rigorously: syngas requirement ≈ 9,000-10,000 Nm3 CO+H2 per tonne of FT products
Natural gas consumption: approximately 7.5-8.5 GJ per GJ of FT product (LHV basis)
Overall GTL energy efficiency: 1/8 = 12.5% (extremely low - GTL is energy-intensive)**

**Wait - this seems too low. Industry reports 60-65% overall energy efficiency for GTL. Recalculate:
The correct figure: GTL plant overall thermal efficiency = 58-65% (LHV basis)**

**The 7.5-8.5 GJ/GJ figure was incorrect. Correct value from Shell Pearl experience:
Natural gas input: 1.65 GJ per GJ of liquid product = energy efficiency = 1/1.65 = 60.6% energy efficiency**

2.2 Commercial GTL Economics - Shell Pearl and Sasol Experience

GTL project economics - large-scale commercial case (Shell Pearl analog):

Plant capacity: 140,000 bbl/day GTL products
Natural gas feed: 1.6 GJ/GJ product x 140,000 bbl/day x 5.8 GJ/bbl = 1,292,800 GJ/day = 1.293 PJ/day natural gas**

**At $4/GJ natural gas: Daily feed cost = 1,292,800 x $4 = $5,171,200/day feed cost**

**Annual feed cost: $5.17M x 365 = $1,888M/year natural gas feed**

**Product revenue (GTL diesel premium: $5-10/bbl over crude oil equivalent):
GTL diesel: 140,000 bbl/day x ($72/bbl crude + $7/bbl GTL premium) = 140,000 x $79 = $11,060,000/day
Annual revenue: $11.06M x 350 operating days = $3,871M/year product revenue**

**Annual Opex: $850M/year (personnel, maintenance, utilities)
Annual gross margin: $3,871M - $1,888M - $850M = $1,133M/year**

**Plant Capex: Shell Pearl actual cost: $18-19 billion for 140,000 bbl/day
Annual Capex charge: $18.5B x CRF(12%, 25 years) = $18.5B x 0.1275 = $2,359M/year**

**Net annual position: $1,133M - $2,359M = -$1,226M/year → GTL loses money at $72/bbl crude, $4/GJ gas**

**Break-even oil price (at $4/GJ gas):
Need: Gross margin = Capex charge
(140,000 x 350 x (P_oil + $7)) - $1,888M - $850M = $2,359M
49,000,000 x (P_oil + 7) = 2,359 + 1,888 + 850 = 5,097M
(P_oil + 7) = 5,097M/49,000,000 = 104.02
P_oil = $97.02/bbl break-even oil price for Shell Pearl-scale GTL at $4/GJ gas**

**At $2/GJ gas (US shale gas levels):
Feed cost: $944M/year
Gross margin: $3,871M - $944M - $850M = $2,077M/year
Break-even oil price: (49M x (P_oil + 7)) = 2,077 + 2,359 = 4,436M → P_oil + 7 = 90.5 → P_oil = $83.5/bbl at $2/GJ gas**

**GTL economics are fundamentally challenging at any oil price below $85/bbl unless gas is available at $2/GJ or less AND the capital cost can be reduced by 30-40% from Pearl levels.

The economics were designed for $100+ oil with stranded gas at $1-2/GJ. At $65-75/bbl crude and $4+/GJ gas, large-scale conventional GTL is not commercially viable without significant capital cost innovation.

3. Methanol-to-Jet: Sustainable Aviation Fuel Pathway

3.1 MTJ Process Chemistry and Yield

Sustainable Aviation Fuel (SAF) from methanol (the Methanol-to-Jet pathway, MTJ) is emerging as a technically and commercially promising route to producing drop-in jet fuel from renewable or low-carbon feedstocks. The process converts methanol first to dimethyl ether (DME) or olefins, then to a hydrocarbon mixture that includes jet fuel range components (C8-C16) through oligomerization, hydrogenation, and fractionation:

MTJ process steps and mass balance:

Step 1: Methanol dehydration to DME
2CH3OH → CH3OCH3 + H2O (over gamma-alumina catalyst at 250-300°C)
Conversion: 80% methanol to DME per pass, 98% overall with recycle

Step 2: DME to olefins (DTO)
DME cracks over zeolite catalyst (SAPO-34 or ZSM-5) to ethylene and propylene primarily
Conditions: 350-450°C, near atmospheric

Step 3: Olefin oligomerization to jet range
Ethylene and propylene oligomerize over acid catalyst to C8-C16 olefins
Conditions: 100-200°C, 30-60 bar

Step 4: Hydrogenation and fractionation
Olefins hydrogenated to paraffins over Ni or Pd catalyst
Distillation separates jet fuel (C8-C16) from gasoline (C5-C8) and diesel (C16+) fractions

Overall MTJ mass balance per tonne of methanol feed:
Jet fuel yield: approximately 0.35-0.45 kg jet fuel per kg methanol (35-45% mass yield)
Gasoline co-product: approximately 0.15-0.20 kg/kg methanol
Diesel co-product: approximately 0.10-0.15 kg/kg methanol
Water + losses: remainder

At 0.40 kg jet/kg methanol (midpoint estimate):
100,000 tonne methanol/year → 40,000 tonnes jet fuel/year**

**Convert to volume: 40,000 tonne / 0.800 tonne/m3 = 50,000 m3/year = 50,000/0.159 = 314,465 barrels jet fuel/year**

**Carbon intensity of MTJ-SAF from e-methanol:
Per tonne jet fuel: methanol required = 1/0.40 = 2.5 tonne methanol
CO2 consumed in methanol synthesis: 2.5 x 1.375 = 3.4375 tonne CO2
CO2 emitted when jet fuel burns: per tonne jet fuel, C content = 86% → CO2 = 0.86 x 44/12 = 3.15 tonne CO2/tonne jet
Net CO2 = 3.15 emitted - 3.44 consumed = -0.29 tonne CO2/tonne jet fuel (net carbon negative!)**

**This net-negative result occurs when the CO2 source for methanol synthesis is direct air capture (DAC) - the fuel literally removes CO2 from the atmosphere. If CO2 is from industrial point source (cement, steel), the fuel is carbon-neutral but not net-negative.

SAF carbon intensity vs fossil jet fuel:
Fossil jet fuel: 3.15 tonne CO2/tonne fuel = 88 gCO2/MJ (well-to-wake)
MTJ-SAF from e-methanol with DAC CO2: approximately 5-15 gCO2/MJ (well-to-wake, including electricity carbon)
Carbon intensity reduction: >83% vs fossil jet fuel

CORSIA (Carbon Offsetting and Reduction Scheme for International Aviation) requires ≥10% lifecycle GHG reduction for eligible SAF → MTJ with green electricity massively exceeds this threshold

3.2 SAF Price Premium and Market Development

SAF Pathway	Feedstock	Current LCOF ($/L)	GHG Reduction vs Fossil	Technology Readiness
HEFA (Hydroprocessed Esters and Fatty Acids)	Used cooking oil, animal fats, vegetable oils	$1.50-2.50/L	60-80%	Commercial (TRL 9)
Alcohol-to-Jet (ATJ) from bio-ethanol	Corn, sugar cane, lignocellulosic biomass	$1.80-3.00/L	40-85%	Commercial (TRL 8-9)
MTJ from green methanol (e-fuel)	Renewable electricity + CO2 (DAC or industrial)	$4.00-8.00/L (2024)	85-95% (DAC) or 70-85% (industrial CO2)	Demonstration (TRL 6-7)
FT-SAF from blue syngas + CCS	Natural gas via ATR + CCS → FT synthesis	$1.80-2.80/L	50-70% (depends on CCS capture rate)	Early commercial (TRL 7-8)
Fossil jet fuel (Jet-A1 baseline)	Crude oil via atmospheric distillation + hydroprocessing	$0.65-0.90/L	0% (reference)	Fully commercial

3.3 SAF Premium Absorption: Airline Economics

SAF cost impact on airline ticket price:

Fuel cost as fraction of airline operating cost: typically 20-25%

For a medium-haul flight (3,500 km, Boeing 737-type aircraft):
Fuel consumption: 5,600 kg jet fuel = 7,000 L per flight
Fossil fuel cost: 7,000 x $0.75/L = $5,250 per flight
Passenger count: 180 passengers
Fuel cost per passenger: $5,250/180 = $29.17/passenger fossil fuel cost**

**SAF blend (10% SAF mandate, EU SAF regulation 2025+):
SAF blend: 700 L at $6.00/L (e-fuel), 6,300 L at $0.75/L (fossil)
Blended fuel cost: 700 x $6.00 + 6,300 x $0.75 = $4,200 + $4,725 = $8,925 per flight**

**Additional cost vs fossil-only: $8,925 - $5,250 = $3,675 per flight
Cost increase per passenger: $3,675/180 = $20.42/passenger for 10% SAF blend at $6.00/L e-fuel**

**At 50% SAF blend (EU 2040 target):
SAF: 3,500 x $6.00 = $21,000, Fossil: 3,500 x $0.75 = $2,625
Total: $23,625 vs $5,250 fossil only → additional $18,375/flight = $102.08/passenger

At 50% e-fuel blend: average medium-haul ticket cost increases by $100+. This is why SAF mandates are phased gradually and why cost reduction in e-fuel production is the critical enabler of aviation decarbonization.

Break-even SAF price for carbon-neutral airline tickets (zero additional cost vs fossil + carbon offset):
Carbon offset price for fossil flight: 7,000 L x 2.5 kg CO2/L = 17,500 kg CO2 x $85/tonne = $1,488
For SAF to be cost-equivalent to fossil + offsets at 50% blend:
3,500 x P_SAF + 3,500 x 0.75 = 5,250 + 1,488 = 6,738
3,500 x P_SAF = 6,738 - 2,625 = 4,113
P_SAF = 4,113/3,500 = $1.175/L SAF break-even price (at $85/tCO2 carbon offset price)

4. Natural Gas-Based Blue Synthetic Fuels: The Near-Term Pathway

4.1 Blue Methanol from ATR + CCS

Blue methanol production cost (ATR + CCS pathway):

Plant capacity: 500,000 tonnes methanol/year (world-scale plant)
Natural gas feed: at 29.7 GJ/tonne methanol (ATR-based): 500,000 x 29.7 = 14,850,000 GJ/year
At $4.4/GJ: Annual feed cost = 14,850,000 x $4.4 = $65,340,000/year**

**Plant Capex: ATR methanol plant at world scale: $800M
CCS addition (capture + compression + storage): $250M
Total Capex: $1,050M
Annualized Capex: $1,050M x CRF(10%, 20yr) = $1,050M x 0.1175 = $123.4M/year**

**Annual Opex (12% of Capex): $126M/year

CO2 capture credits: 500,000 t MeOH x 0.95 tCO2/t MeOH x 91.6% capture x $85/t = $36.9M/year

Total annual cost: $65.3M feed + $123.4M Capex + $126M Opex - $36.9M CCS credits = $277.8M/year**

**Blue methanol LCOP: $277.8M / 500,000t = $555.6/tonne = $0.555/kg blue methanol**

**Compare to: Fossil methanol spot price: $300-450/tonne (2024 market)
Green methanol production cost (100 MW plant, 100,000 t/year): approximately $800-1,200/tonne

Blue methanol at $556/tonne is competitive with fossil methanol at $450/tonne with only modest carbon pricing, and is well below green methanol cost of $800-1,200/tonne.

Blue methanol premium vs fossil methanol: $556 - $400 (midpoint fossil) = $156/tonne = 39%
At $150/tCO2: CCS credits increase to $65.1M/year → blue methanol LCOP = $242.5M/500,000t = $485/tonne → nearly competitive with fossil methanol unsubsidized

Conclusion

The GTL break-even oil price calculation in this article - $97/bbl at $4/GJ natural gas for a Shell Pearl-scale plant - explains definitively why large-scale conventional Gas-to-Liquids development has stalled since the early 2010s and why the projects built during the 2000-2010 period (when oil was above $80/bbl and trending toward $100+) have struggled to generate acceptable returns. The capital intensity of GTL at $18-19 billion for 140,000 bbl/day capacity is simply too high for a technology whose only competitive advantage is converting abundant low-value natural gas into premium liquid fuels: when oil prices fall below $85/bbl (which they have for the majority of the period since 2015), the GTL spread disappears. The only economically rational configuration for future GTL development combines ultra-cheap stranded gas (below $1.5/GJ), modular capital-efficient plant design (reducing capital intensity by 40-50% from Pearl levels), and integration with CCS to capture the blue synthetic fuel premium. All three conditions must be met simultaneously for GTL to achieve acceptable returns at $70-80/bbl oil.

The MTJ-SAF carbon intensity calculation - net carbon-negative at -0.29 tonne CO2/tonne jet fuel when direct air capture CO2 is used - demonstrates why e-fuel SAF is attracting intense investor interest despite its current $4-8/liter production cost. Aviation is one of the hardest sectors to decarbonize: batteries cannot power long-haul aircraft at commercially viable weight, and hydrogen requires complete redesign of aircraft airframes and airport infrastructure. Synthetic aviation fuel produced from renewable electricity and atmospheric CO2 is the only near-term pathway that requires no changes to aircraft design, airport infrastructure, or fuel distribution systems, while achieving the deep decarbonization that CORSIA and national aviation climate commitments require. The $4-8/liter current production cost will decline as electrolyzer costs fall and renewable electricity prices decrease, following the same cost reduction trajectory that made utility-scale solar power cheaper than coal within 15 years of becoming competitive. The question is not whether e-fuel SAF will become cost-competitive with fossil jet fuel, but whether its cost trajectory is fast enough to meet the 2035-2050 aviation decarbonization targets without excessive intermediate subsidization.

For engineers and analysts building expertise in synthetic fuel production and techno-economics, the following references provide the essential framework: Gas-to-Liquids and Synthetic Fuels - Chemistry, Engineering, and Economics covers FT synthesis, methanol production, and GTL process design in comprehensive detail, while Sustainable Aviation Fuel and Power-to-X Technologies provides the technical and economic framework for SAF pathways including MTJ, ATJ, HEFA, and FT-SAF production and certification.

Want to access our synthetic fuels toolkit with methanol synthesis stoichiometry calculator, ASF product distribution model, GTL break-even oil price calculator, MTJ-SAF carbon intensity estimator, blue methanol LCOP model, and SAF airline ticket cost impact calculator, or discuss synthetic fuel project economics for a specific feedstock and market? Join our Telegram group for synthetic fuels and energy transition economics discussions, or visit our YouTube channel for step-by-step tutorials on methanol synthesis, Fischer-Tropsch chemistry, and SAF production economics.

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