Upstream Process Flowsheets & Simulations
Explore 2 validated, solved Upstream simulation flowsheets in MaximaLabs — real components: methane, ethane, propane, n_butane, co2, n2. Open any one directly in your browser.
Solved via: PENG-ROBINSON.
Wellhead gathering — cold separation and the hydrate check
A wet-gas wellhead through a JT choke, a cold separator and a gathering line — the flowsheet that gives HYSYS Upstream's own tools (well IPR, hydrates, water content, gas pipeline) something real to work on. All four are in the Analysis panel and none had a curated example. From the flowsheet. 800 mol/s of wet gas lets down 120 to 60 bar across the choke, cooling itself to 294 K by Joule-Thomson alone; a chiller takes it to 250 K (2.6 MW) and the cold separator drops 88.5 mol/s of condensate (11%), sending 711.5 mol/s of sales gas down 25 km of 300 mm line for a 3.8 bar drop at 2.4 m/s. Well deliverability (Analysis > Well IPR). Vogel's composite IPR from one test point (0.045 at 200 bar flowing bottomhole, against a 240 bar reservoir and a 180 bar bubble point) gives an absolute open flow of 0.18 and, at 120 bar flowing pressure, a deliverability of 0.125 — the curve that says whether the well can actually feed this train. The hydrate check (Analysis > Hydrates, Water content). This is the pair that matters and the reason the two tools belong together. At 60 bar the gas is water-saturated at 21.2 lb/MMscf with free water present; Towler-Mokhatab puts the hydrate formation temperature at 291.2 K. Operating anywhere near seabed or winter temperature — 288 K, say — is 3.2 K inside the hydrate envelope, calling for about 20.5 wt% MEG to stay clear with a 3 K margin. A line that is hydraulically fine can still plug solid. **.
7 unit ops • PENG-ROBINSON
82 1
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
9 0
View & open