Co-hydrogenation: vegetable oil co-processed in a gasoil hydrotreater — a PENG-ROBINSON process flowsheet
Rapeseed-type vegetable oil (modelled as triolein) co-processed at 7.3 wt% in a sulfur-bearing gasoil (n-hexadecane carrier with a dibenzothiophene slice) over a sulfided hydrotreating catalyst at 70 bar and 613-633 K, the way refineries put renewable carbon into diesel without a separate HVO unit. The triglyceride leaves by three routes, each written as its own conversion reactor with an exact element balance: hydrodeoxygenation (triolein + 15 H₂ → 3 n-C₁₈ + propane + 6 H₂O), decarboxylation (triolein + 6 H₂ → 3 n-C₁₇ + propane + 3 CO₂) and decarbonylation (triolein + 9 H₂ → 3 n-C₁₇ + propane + 3 CO + 3 H₂O); the glycerol backbone becomes propane in all three, and the double bonds are saturated in the same step. The gasoil is desulfurized in parallel (dibenzothiophene + 2 H₂ → biphenyl + H₂S). The effluent goes through a hot and a cold high-pressure separator; an amine wash (a fixed-recovery separator) takes H₂S and CO₂ out of the recycle gas, a 5% purge bleeds the CO and propane the wash cannot, and the recycle compressor closes the hydrogen loop. The separator liquids lose their water in a knock-out, are let down to 3 bar, flashed, and steam-stripped into the co-processed diesel.
What the split costs in hydrogen is the point of the example: at 60% HDO, 30% decarboxylation and 10% decarbonylation the oil consumes 11.7 mol H₂ per mol triglyceride, against 15 for pure HDO and 6 for pure decarboxylation; with the 2.97 mol/s the desulfurization takes, chemical consumption is 14.67 mol/s, and the hydrogen leaving in the purge, the flash gas and the stripper overhead is set against the 30 mol/s makeup. The split leaves its fingerprint in the product: the diesel carries n-C₁₇ and n-C₁₈ in a 0.67 mole ratio, which is the measurement a refinery uses to infer the route.
Modeling assumptions & limitations
- 1The pathway split is a stated screening INPUT, not a prediction. The co-processing literature reports both routes operating on sulfided NiMo/CoMo, with their balance set by catalyst and conditions (Huber, O'Connor & Corma, Appl. Catal. A 329
- 2120; Donnis et al., Top. Catal. 52
- 3229; Kubicka & Kaluza, Appl. Catal. A 372
- 4199); the 60/30/10 numbers are illustrative within that picture, and the n-C₁₇/n-C₁₈ ratio of a real product is what should replace them.
- 5The triglyceride record carries no ideal-gas heat-capacity correlation and no heat of formation, so no heat of reaction is booked: every reactor is temperature-specified and its duty is sensible heat only, not the exotherm a real bed removes with quench gas.
- 6Water-gas shift and CO methanation, which move CO and CO₂ around in a real loop, are not modelled; CO accumulates until the purge carries it out.
- 7The oil is one triglyceride and the gasoil one paraffin plus one sulfur species; there is no aromatic saturation, no cracking and no hydroisomerization. The atom balances are exact; the hydrogen bookkeeping follows from them.
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- Rigorous PENG-ROBINSON thermodynamics, solved by the same engine every simulation runs on.
- 9 unit operations modeled: 3× Liquid MIX, 3× COOL, 4× HDS, 3× LP SEP, 2× Water KO, Recycle Split, Recycle COMP, Letdown, Stripper.
- Focus areas: Co-processing, Hydrotreating, HDO, Decarboxylation, Renewable diesel, H2 recycle, Desulfurization.
- Thermodynamics
- PENG-ROBINSON
- Components
- triolein_ooo, n_hexadecane, dibenzothiophene, h2, n_octadecane, n_heptadecane, propane, water, co2, co, h2s, biphenyl
- Unit operations
- 3× Liquid MIX3× COOL4× HDS3× LP SEP2× Water KORecycle SplitRecycle COMPLetdownStripper
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("vegetable-oil-gasoil-co-hydrogenation")
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
Diesel hydrotreater with closed H2 recycle + amine wash
Diesel (an n-hexadecane carrier with a dibenzothiophene sulfur slice) and hydrogen react over a trickle-bed-equivalent reactor (dibenzothiophene + 2 H₂ → biphenyl + H₂S, the direct-desulfurization route; C₁₂H₈S + 2 H₂ balances, and the 3 H₂ this example once carried destroyed two hydrogen atoms per molecule) after a fired-heater preheat, at a treat-gas rate of ~3 mol H₂ per mol oil (~380 Nm3/m3) — the hydrogen excess that keeps the catalyst wet with H₂, not the 0.06 stoichiometric need. The effluent is cooled to 520 K (a real unit's feed/effluent exchange) before the hot high-pressure separator takes the gas off; a cold separator at 290 K condenses the carried-over oil; an amine wash (a fixed-recovery separator — the same simplification the carbon-capture example uses, not a full electrolyte amine model) scrubs H₂S from the recycle gas, and a compressor closes the loop with a 3% purge. The separator liquids are let down to 3 atm: a low-pressure separator flashes off the dissolved hydrogen and most of the H₂S as sour gas, and a six-stage steam stripper (Kremser, ~10 mol% stripping steam) finishes the desulfurized diesel. Every hydrogen atom is accounted for: makeup = reaction consumption + purge + sour gas + stripper overhead. History, because it changed the solver: this flowsheet used to run 6 mol/s of makeup on 50 mol/s of oil. All of that hydrogen dissolved in the hot liquid, both separators produced no gas, and the recycle the stream table showed was a stale tear iterate the loop had accepted as converged — the flowsheet now clears an edge its unit did not feed, so a loop can no longer converge onto a stream it fabricated. The refluxed stripper column that fed on it, asked to hold supercritical H₂S in a 600 K bottoms under a 239 K H₂S reflux, lost a fifth of its hydrogen and was gated unconverged for the same reason.
Renewable diesel & SAF: HEFA hydrotreating train
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.
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.