Renewable diesel & SAF: HEFA hydrotreating train — a PENG-ROBINSON process flowsheet
The HEFA (Hydroprocessed Esters and Fatty Acids) pathway to sustainable aviation fuel and renewable diesel from fats/oils/greases: a triglyceride feed (triolein) plus a large hydrogen excess is hydrodeoxygenated (HDO) to n-paraffins + propane + water, the paraffins are hydrocracked/isomerized toward the jet range, the H₂-rich recycle gas and the HDO process water are knocked out, the light ends are stabilized, and a two-column fractionation splits the product into light naphtha, a jet-range SAF cut, and renewable-diesel bottoms.
Modeling assumptions & limitations
- 1The databank carries no lauric/oleic assay, so the FOG feed is modeled as triolein hydrodeoxygenating to n-octadecane (real HDO stoichiometry: triolein + 15 H₂ → 3 n-C₁₈ + propane + 6 H₂O); the hydrocracking lump (n-C₁₈ → n-C₁₂ + n-C₆) is illustrative, not a fitted kinetic network; and the n-/iso-paraffin distinction that actually sets the jet freeze-point spec is NOT resolved (the databank carries n-paraffins, not the specific branched isomers) — the train computes real material/energy balances and a real fractionation, not a validated freeze-point. A 3-phase water knockout is modeled as a component separator (the real unit gravity-decants the sour water).
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- Rigorous PENG-ROBINSON thermodynamics, solved by the same engine every simulation runs on.
- 7 unit operations modeled: MIX, HDO, HC, 2× Lpsep, Water KO, Letdown, 2× JET COL.
- Focus areas: SAF, HEFA, Renewable diesel, Hydrotreating, Hydrodeoxygenation.
- Thermodynamics
- PENG-ROBINSON
- Components
- triolein_ooo, n_octadecane, n_dodecane, n_hexane, propane, water, h2
- Unit operations
- MIXHDOHC2× LpsepWater KOLetdown2× JET COL
Opens in a new tab, loaded straight into the app — no setup.
Read the step-by-step guideReproduce this exact result from Python — the real client.get_example() → run_and_wait() path, not a mockup.
from flowsim.sdk import FlowSimClient
client = FlowSimClient()
example = client.get_example("saf-hefa-renewable-jet")
sim = client.create_simulation(example["title"], example["flowsheet"])
result = client.run_and_wait(sim["id"])
print(result["status"]) # "converged"
streams = client.streams(sim["id"])Related models
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Diesel (an n-hexadecane carrier with a dibenzothiophene sulfur slice) and hydrogen react over a trickle-bed-equivalent reactor (dibenzothiophene + 3H2 → biphenyl + H₂S, the real HDS desulfurization route) after a fired-heater preheat. Hot and cold high-pressure separators knock the light gas off the treated oil; an amine wash (a fixed-recovery separator — the same simplification the existing carbon-capture example uses, not a full electrolyte amine model) scrubs H₂S from the recycle gas before a compressor closes the loop back to the reactor feed, with a small purge controlling buildup. A pressure-letdown valve + stripper finish the treated oil, removing dissolved light ends before the desulfurized diesel leaves the bottoms.
Sustainable Aviation Fuel via Alcohol-to-Jet
Bio-ethanol is catalytically dehydrated to ethylene, oligomerized toward a decene-range olefin, then hydrogenated to n-decane — a real synthetic paraffin in the SAF/jet-range carbon-number band.
LNG front end and storage: guard beds, tank boil-off, driver limit
The parts of a 5.2 Mtpa LNG train that are not the cold box, and the four questions they answer that no bulk unit can — at real capacity, so the vessel sizes and duties are ones an engineer can check against their own plant. Guard beds: a sulfur-carbon bed takes mercury from 200 to 0.01 µg/Nm³ — the brazed-aluminium limit, because mercury attacks the plate-fin cold box by liquid-metal embrittlement — on a 4.8 m x 6.6 m bed with 4.2 years of life from a capacity balance — inside the 3-5 year window these non-regenerable beds are actually replaced on, which is what a turnaround plan needs. A 4A molecular sieve then dries the gas to 0.1 ppmv, the only route to a cryogenic water spec (a glycol contactor tops out near a −30 °C dew point), on a 4.9 m x 5.1 m bed running a 13.8 h cycle for 1.3 MW of regeneration duty. Storage: the LNG goes to a tank whose boil-off rate comes from a 0.05%/day guarantee but whose boil-off composition comes from a real equilibrium flash — and that is the interesting part, because the vapour leaves at ~11 mol% nitrogen against 1.1% in the feed. Nitrogen and methane are far more volatile at 113 K, so the boil-off is light and the stored liquid weathers heavier: nobody specified that, the flash found it. Recondensing: the boil-off goes back into the send-out LNG rather than to a flare, and the unit reports the LNG:BOG ratio (1999) against the minimum the energy balance demands (3.8), which is the constraint a terminal is actually operated against. The driver: a gas turbine burning plant fuel gas, rated 97.5 MW at ISO conditions, delivers only 84.5 MW at 35 °C — 5.5 MW short of its 90 MW refrigeration load, and flagged as such. That derate is computed from two physical effects (a fixed-geometry compressor swallows a fixed volume so mass flow follows air density, and hotter air costs more to compress), not from a vendor curve, and it comes out at 0.66%/K — mid-band for industrial machines. It is why a tropical LNG train makes less product in summer.
Gas-condensate LNG train: condensate, LPG and LNG
The LNG plant that is also a liquids plant, at real capacity: this is one 4.4 Mtpa train (a two-train plant is two of these), not a scaled-down sketch. A condensate-rich field arrives by trunkline as a two-phase stream: the slug catcher drops ~20 mol% of it out as raw condensate before a single molecule reaches the cold end, and the plant then runs two trains side by side off one feed. Liquids: the raw condensate is let down to an MP flash that strips the dissolved methane (without it the stabilizer's shortcut total condenser tries to condense methane at 8 bar, which is not a real stabilizer overhead), then stabilized to a C₅/C₆ product. Gas: sweetened and dried, chilled to 245 K to knock out an NGL cut, and the NGL demethanized and split by a deethanizer / depropanizer / debutanizer sequence into commercial propane (~98 mol%) and butane (~98 mol%) LPG plus a natural-gasoline bottoms. LNG: the lean gas goes to the same APCI C3MR cold end as the 'c3mr-lng-liquefaction' showcase — propane precool, mixed-refrigerant MCHE to 120 K, JT letdown to a 1.5 bar end-flash drum. Five sold products come out of one flowsheet, each a stream the solver computed. Watch the end-flash boil-off: it leaves at ~13 mol% nitrogen against 1 mol% in the feed, because the flash drum is where an LNG train actually rejects its nitrogen — nobody specified that, the flash found it. Dehydration is the real molecular-sieve bed, not a stand-in: a 4A sieve sized by length-of-unused-bed, which is what actually takes the gas to the <=0.1 ppmv the cold box needs — 95 t of sieve on a 5.5 x 5.5 m bed, a 17.5 h cycle and 1.4 MW of regeneration duty, with 0.47 bar of Ergun pressure drop. The AGRU spec is checked against the physics rather than assumed: 99.9% CO₂ removal leaves 33 ppmv, and at the coldest point in the train (115.9 K) the solid-CO₂ solubility limit is 232 ppmv on the measured-data basis — a 7x margin, so the sweetening spec demonstrably clears freeze-out instead of merely looking tight.
Deep ethane recovery with propane-refrigerated feed chilling
Associated gas is chilled by an external propane refrigeration package before a demethanizer recovers ethane and heavier as NGL bottoms from a methane-rich residue gas overhead — the cryogenic-chilling role Ortloff's CCS/GSP processes play ahead of the turboexpander in a real deep-ethane-recovery plant. The mechanical refrigeration loop itself (compressor/condenser/valve) isn't separately modeled here; the chiller's duty is represented directly as the feed's cooled outlet temperature (the same honest-simplification pattern used for LNG cold-box examples elsewhere in this library).
Gas compressor air-cooled aftercooler (fin-fan)
A natural-gas booster compressor followed by an air-cooled (fin-fan) aftercooler — the standard way to reject compression heat where no cooling water is available. The compressor raises the gas from 8 to 24 atm (hot discharge ~150 °C); the air cooler then rejects that heat to ambient air, cooling the gas back to 49 °C. Unlike a plain cooler, the air_cooler op closes the air side: from the process duty and the 35 °C design ambient it solves the air mass flow (a 15 °C air rise) and reports the fan power from the given fan static pressure. Honest scope: screening air-side model (fixed cp_air, ideal-gas air density, no fin/row geometry rating); an air cooler cannot cool below ambient, so the 49 °C target sits safely above the 35 °C air inlet.