This is Edition 5 of a series on Fischer-Tropsch technology for non-technical audiences — investors, developers, and stakeholders in renewable fuels. Earlier editions covered the FT process, upgrading, emerging applications, the three main technology types, and the economics of small-scale Fixed Bed FT. I’m David Lloyd, CCO of Emerging Fuels Technology (EFT), a leading licensor of FT and upgrading technologies.
Declared interests: EFT designs and licenses both FT catalyst systems and the upgrading processes discussed here. I’ll be clear where I’m making a general argument versus describing EFT’s specific approach.
In Edition 2, I introduced the concept of alpha — the most important number that describes what comes out of an FT reactor. A high alpha means more longer hydrocarbon chains; a low alpha means more shorter ones. I flagged then that Alpha is “a critical consideration in FT technology design that we’ll return to in Edition 5.” So here we are. Alpha is critical because its impact is felt upstream in the syngas module (due to recycling), the sizing of the FT reactor itself, and most directly downstream in upgrading.
I also mentioned in Edition 2 that besides the distribution determined by alpha, there are separate drivers of the production of methane. These include reaction conditions (temperature and pressure), catalyst properties, and mass & heat transport (which are functions of both catalyst and reactor design). We shall see why high methane selectivity is problematic.
The upshot is that FT catalyst, reactor, and upgrading are not independent choices you can optimise separately and assemble later. They need to be considered as a single system – treating them otherwise will cost you dearly.
Before making the positive case, it’s worth examining two alternative strategies that circulate in the FT industry, because both sound superficially plausible (so naturally VCs love them) but both give sub-optimal outcomes.
The low-alpha, no-hydrocracker approach
The logic runs like this: if you run a low-alpha catalyst that produces shorter chains, you avoid making waxes, and therefore you eliminate the need for a hydrocracker. The hydrocracker represents roughly 10% of total plant capital — so eliminating it sounds like a meaningful saving.
The problem is what you get instead. At low alpha, roughly half of everything your reactor produces is in the range of 1 to 4 carbon atoms (C1-C4) — light gases that aren’t marketable liquid fuel. To avoid wasting that carbon, you have to recycle those gases back into your syngas generation system. But syngas generation is often 60–65% of your total plant capital. Making it, and the FT reactor, larger to handle the recycle more than cancels out the money you saved by eliminating the hydrocracker — and then some.
There’s a yield penalty too. Of the liquid product you do recover, more than 60% is in the naphtha range — the least valuable fraction, well below jet and diesel in market value. But it gets worse for anyone planning to produce SAF: jet fuel has a freeze point specification of -40°C that straight-chain FT paraffins cannot meet without isomerization. An isomerization unit is essentially the same equipment as a hydrocracker. So, you end up needing the hydrocracker-equivalent anyway, while also carrying the cost of a bloated syngas system, oversized FT reactor, and a low-value product slate. But the final irony is you can do the isomerization and hydrocracking in a single unit by using the right mix of catalysts (which is what Emerging Fuels Technology does).
The combined FT-and-hydrocracker-in-one-reactor approach
The idea here is to stack FT catalyst and hydrocracking catalyst in the same reactor, running both reactions simultaneously.
The fundamental obstacle is temperature. FT synthesis runs at 180–220°C. Hydrocracking needs 250–350°C. You can’t run both optimally in the same vessel at the same time — so you have to compromise both. The hydrocracking conversion is further compromised by having to operate in the presence of carbon monoxide.
The net result: like the no-hydrocracker approach, it is technically possible, but the compromises to output yield and selectivity outweigh the saving from eliminating the hydrocracker.
So, the best strategy is a high-alpha catalyst with a separate, dedicated upgrading system. But “separate upgrading system” is where a further error commonly enters: the assumption that you should ship your FT liquids to an existing petroleum refinery and have them upgraded there to share in economies of scale.
This is using a sledgehammer to crack a nut.
Conventional refinery upgrading is designed for crude oil — a complex, variable mixture of hydrocarbons including olefins and aromatics (amongst others), also contaminated with sulphur and nitrogen compounds, salts and heavy metals. To handle all of that, refinery hydrocrackers incorporate decontamination and operate at high temperatures and pressures. The equipment is heavy-duty, expensive, and engineered to cope with a feedstock that is, in chemical terms, a mess.
FT liquids are the opposite of a mess. As Edition 2 described, they contain essentially no sulphur, no aromatics, and no olefins. The feedstock is pure, predictable, and consistent. A purpose-built FT upgrading unit can therefore operate at lower temperatures and pressures than a conventional refinery hydrocracker — and that means cheaper equipment and lower operating costs. Importing refinery severity into an FT upgrader is not just unnecessary; it’s actively wasteful.
So, returning to the ill-conceived quest to avoid upgrading modules in the previous section, part of the problem is that the true cost of hydrocracking the output from an FT reactor is overestimated – the sledgehammer being considered is much more expensive than the nutcracker.
A further problem with shipping raw FT liquids to a refinery for upgrading is that they will almost certainly be co-processed with crude oil — blended in with the main feed and run through the sledgehammer at refinery conditions. You lose control over your final product specifications. The purity that makes FT products valuable for synthetic oils, including transformer oils and data centre immersion cooling fluids described in Edition 2, is squandered.
But to be fair, there is a significant advantage to using an existing oil refinery – and that is to access the fuel supply chain, which greatly simplifies logistics. This is a legitimate choice, particularly in the early days of SAF industry scaling up, and for as long as it is required to blend SAF with fossil jet.
The alternative that actually works is to maximise alpha and design upgrading specifically for the FT product — not as an afterthought, but from the very beginning, as a single integrated system.
At an alpha of 0.93, approximately 90% of what the FT reactor produces is in the liquid (C5+) range. The output is heavily weighted toward long-chain molecules — the waxes and heavy fractions that are perfect feedstock for a properly designed hydrocracker. After cracking, jet or diesel yields exceed 80%, with minimal recycling of light gases back to syngas generation. This means the syngas generation system — the most capital-intensive part of the plant — can be sized for the actual feed, not inflated by recycle. The whole system (including the FT reactor itself) is smaller, cheaper, and more efficient than any low-alpha alternative.
For eFuels projects, where the primary feedstock cost is renewable electricity rather than a combustible gas, this efficiency gain is even more significant. Every barrel of recycled light gas that has to be reformed back to syngas represents electricity that was used to make a product you then had to unmake. Maximizing alpha and minimizing recycle is therefore a direct reduction in power consumption per barrel of marketable product — a critical metric when electricity costs dominate.
The upgrading system for a high-alpha product also presents its own design opportunity. EFT’s stacked-bed hydrocracker/isomerizer is purpose-designed for heavy FT syncrude, operating at lower pressure than a conventional refinery hydrocracker. No heavy-duty equipment needed for sulfur and nitrogen removal. No aromatics saturation. The capital cost of the entire upgrading system — cracking, isomerization, and distillation — can be kept below 10% of total plant installed cost without sacrificing yield or product quality.
What this means in practice
The lesson from all of this is that FT catalyst choice and upgrading design are not sequential decisions. You cannot pick a catalyst then go looking for an upgrading solution afterward (or worse – start with an upgrading solution in the belief you can just plug in any old FT reactor) without bringing on a host of inefficiencies that cascade through the whole process. Possible? Yes. Wise? No.
Investors evaluating FT projects should ask: are the catalyst and upgrading system designed as an integrated package by the same team, or assembled from unrelated components? Is the upgrading purpose-matched to the FT product, or borrowed from crude oil refinery practice? The answers matter as much as many other more obvious technical questions in a project’s design.
Has upgrading been a significant line item or technical challenge in any FT or renewable fuel projects you’ve been involved with? I’d be interested to hear how it’s been approached — comment below.
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