Gas processing Process Flowsheets & Simulations
Explore 8 validated, solved Gas processing simulation flowsheets in MaximaLabs — real components: methane, ethane, propane, co2, n_butane, n_pentane. Open any one directly in your browser.
Solved via: PENG-ROBINSON, CPA.
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.
4 unit ops • PENG-ROBINSON
138 0
View & openAssociated gas conditioning
Field gas is compressed, chilled below its dew point, and flashed to knock out NGL/condensate — the sales-gas vs. liquids split every midstream gathering plant runs (Peng-Robinson).
6 unit ops • PENG-ROBINSON
226 0
View & openNatural gas fractionation train
A four-column NGL fractionation train — demethanizer, deethanizer, depropanizer, debutanizer — recovering pipeline-spec sales gas plus ethane, propane, and butane products from wellhead-pressure raw natural gas, after Luyben (Ind. Eng. Chem. Res. 2013, 52, 10741).
10 unit ops • PENG-ROBINSON
226 0
View & openCold-separator NGL recovery / dew-point control
A rich natural gas is chilled in the gas/gas exchanger + propane-chiller train (lumped here as one cold box) to -33 degC and let into a cold separator. The heavy hydrocarbons (C3+) drop out as a raw NGL liquid, leaving a leaner sales gas that meets its hydrocarbon dew-point spec — so no more liquid forms as the gas cools in the export pipeline. The cold separator is modelled as an adiabatic flash fed by the chiller, so the single knob (the chill temperature) drives both the NGL recovered and the refrigeration duty: colder recovers more NGL but costs more refrigeration (the built-in sensitivity). Peng-Robinson handles the hydrocarbon VLE; the companion gas-conditioning utilities (hydrate risk, water content, Joule-Thomson choke cooling, and compressor sizing for the sales-gas recompression) quantify the rest of the plant around it.
5 unit ops • PENG-ROBINSON
178 0
View & openDepropanizer (NGL fractionation)
The raw NGL recovered by a cold separator is fractionated: a depropanizer column splits it into a C₃-and-lighter overhead (propane + a little ethane, the LPG product) and a C4+ bottoms (butanes + natural gasoline). The column is solved with the component-flow Naphtali-Sandholm MESH (method "ns"), which carries every component flow as an unknown so the feed-vs-products material balance is an equation the solver closes by construction — the right tool for a sharp C₃/C₄ cut, where a reduced-form column would drag the split off and leak a few percent of a component. Peng-Robinson handles the light-hydrocarbon VLE; the built-in sensitivity sweeps the reflux ratio against the reboiler duty (the classic distillation energy trade-off).
4 unit ops • PENG-ROBINSON
185 1
View & openNGL fractionation train (depropanizer + debutanizer)
The full two-column NGL fractionation train of a gas plant: a raw NGL is split into three products. The depropanizer takes a propane-and-lighter overhead (the propane product), and its C4+ bottoms feed a debutanizer that splits butane overhead from a natural-gasoline (C5+) bottoms. Both columns use the component-flow Naphtali-Sandholm MESH (method "ns") so each sharp cut conserves every component exactly; the two columns solve in sequence (no recycle) and the whole train closes on mass. Peng-Robinson handles light-hydrocarbon VLE; the debutanizer runs at a lower pressure (7 bar vs 18) so its reboiler stays within a reasonable temperature.
6 unit ops • PENG-ROBINSON
186 0
View & openGas dehydration: why the property package decides the answer
A wet pipeline gas at 70 bar and 40 C is chilled to 15 C, the condensed free water is knocked out, and a 4A molecular-sieve bed takes the rest down to the cryogenic 0.1 ppmv spec. It is the standard front end of every gas plant, and it is one number wide: how much water the gas holds at saturation. Everything downstream is arithmetic on that number — the knockout drum's liquid rate, the sieve's cycle time, the bed size, the regeneration duty. Here the feed carries 1500 ppmv (71 lb/MMscf). Chilling to 288 K drops the saturation limit to 313 ppmv (14.9 lb/MMscf), so 3.57 mol/s of essentially pure water (99.9 mol%) falls out in the KO drum for a 3.91 MW chilling duty, and the sieve carries the remaining 0.94 mol/s. A 4000 kg bed then sizes out at 2.69 m diameter by 0.96 m deep on a 7.8-hour cycle — the 8-hour cycle real molecular-sieve dehydrators are built around — with 108 kW of regeneration duty and 11 kPa of bed pressure drop. This example runs on CPA (Cubic-Plus-Association) and not on a cubic, deliberately. Water in a hydrocarbon gas is the case a bare cubic equation of state is worst at: its hydrogen bonding is not a small correction to be absorbed into a binary interaction parameter, it is the thing that sets the answer. CPA adds a Wertheim association term on top of SRK and switches it on only for the hydrogen-bonding species, so hydrocarbons still behave exactly as SRK. Bounded, and the bound is measured. Against the McKetta-Wehe chart's ~60 lb/MMscf for methane at 100 F and 1000 psia, CPA lands at ~55, PR at ~50 and SRK at ~45 — CPA is the closest, and all three still underpredict. None of them has a cited methane-water binary interaction parameter, and extrapolating CPA's published n-alkane correlation (kij = 0.1915 - 0.026*n_carbon, fitted C₃..C₁₀) down to methane would fabricate the number that decides the answer, so it stays absent. Good for a first-cut dehydration duty; not a guarantee-grade contract number.
6 unit ops • CPA
66 0
View & openWellhead compression: what the reservoir gives and what it costs to move
A gas well is not a feed whose flow you type in. The rate is an OUTCOME of how hard the facility pulls on the reservoir, and this example starts there. The well runs the Vogel inflow-performance relationship: at a 250 bar reservoir pressure and a 5e-5 mol/s/Pa productivity index its absolute open flow is J x p_r / 1.8 = 694 mol/s, and the fraction of that you actually get follows 1 - 0.2(p_wf/p_r) - 0.8(p_wf/p_r)^2. Holding 180 bar at the bottomhole delivers 306 mol/s, 44% of open flow. Squeeze to 150 bar and it rises to 411; back off to 240 and it collapses to 49. The curve is deliberately not a straight line — that curvature is why compression pays for itself, and why the last increment of drawdown buys less than the first. Compression is where the stage count earns its keep. Taking that gas from 30 to 150 bar in ONE stage lands the discharge at 508 K (235 C) — past what reciprocating machine valves and lube oil tolerate, before any efficiency argument. Split it into three with intercooling to 313 K and the discharge is 362 K; four stages give 349 K. The temperature, not the power, is what sets the stage count on a real machine. Read the reported duty carefully. duty on this unit is the NET of the compression work and the intercooler heat removed, summed into one number — it goes from +2094 kW at one stage to -384 kW at three, not because compression got cheaper but because there is now intercooling to subtract. It is not shaft power, and this example does not present it as such.
3 unit ops • PENG-ROBINSON
67 0
View & open