Wellhead compression: what the reservoir gives and what it costs to move — a PENG-ROBINSON process flowsheet
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 507 K (234 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 360 K; four stages give 348 K. The temperature, not the power, is what sets the stage count on a real machine. The power still falls: duty on this unit is the shaft work the drivers deliver, 2078 kW in one stage and 1615 kW in three (22% less, because each stage starts cool). The three-stage train's intercoolers reject 2022 kW, reported apart as intercooler_duty and billed as cooling, not power. (Until 2026-10-18 the two were summed into one duty, which read -384 kW at three stages.)
191 views 0 forks
- Rigorous PENG-ROBINSON thermodynamics, solved by the same engine every simulation runs on.
- 2 unit operations modeled: WELL, COMP.
- Focus areas: Upstream, Well, IPR, Vogel, Compression, Gas processing.
- Thermodynamics
- PENG-ROBINSON
- Components
- methane, ethane, propane, co2
- Unit operations
- WELLCOMP
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("wellhead-compression")
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
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.
Associated 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).
Natural 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).
CO₂ capture + compression
Post-combustion capture recovers 90% of the flue CO₂, then a compressor and after-cooler condition it to pipeline pressure for storage/EOR — the real energy cost after capture.
Three-stage condensate stabilization (Soave-Redlich-Kwong)
Wellhead fluid at 60 bar and 320 K — 60% methane with ethane through n-hexane — through a high-pressure separator, a letdown to 15 bar and an adiabatic medium-pressure separator, then to 2 bar and a low-pressure separator, on plain SRK with its shipped kij: the workhorse cubic for hydrocarbons, exactly where it is meant to be used. What it computes: 69 mol/s of HP gas at 76% methane, 10 mol/s of MP flash gas, 5 mol/s of LP gas rich in propane and butane, and 15.9 mol/s of stabilized condensate carrying 0.2% methane and 2.2% ethane — the light ends that would otherwise vent from a tank. The Joule-Thomson cooling across each valve is the model's, not an input: 320 to 304 K at the first letdown, 280 K at the second. No.
Cold-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.