How to simulate teg natural gas dehydration
Wet natural gas is contacted counter-currently with lean triethylene glycol (TEG) in an absorber, pulling water vapor into the glycol to meet a pipeline water spec; the rich glycol is then let down in pressure and regenerated in two flashes — the first flashes off the bulk of the co-absorbed methane, the second (hot) flash boils the absorbed water off the now nearly gas-free glycol, leaving hot lean glycol bottoms (its recycle back to the absorber is reported as a product, the same open-loop simplification used elsewhere in this library). Water is the most common undesirable natural-gas impurity — it forms hydrates that plug valves and fittings once the gas is compressed or cooled.
Also known as: glycol dehydration unit, TEG dehydration, natural gas dehydration unit.
- 1Open the ready-made model
Open the "TEG natural gas dehydration" model in the MaximaLabs workspace — no install, no license. It loads live on the canvas, ready to edit and run.
- 2Confirm the thermodynamics
This process is modeled with the PENG-ROBINSON property package over methane, water, triethylene_glycol — already selected, so the phase equilibrium and enthalpy are physically consistent from the first run.
- 3Review the flowsheet
The flowsheet chains Contactor, Letdown, 2× Regen. Every block is a real, solvable unit op you can reconfigure on the canvas.
- 4Run the simulation
Click Run. The deterministic solver converges the material and energy balances (recycles included) and fills the live stream table — the AI never invents a number.
- 5Read the results and iterate
Inspect the converged streams, tweak a spec, and re-run — or ask the AI copilot to explain a result or diagnose a failed solve in plain English.
- Thermodynamics
- PENG-ROBINSON
- Components
- methane, water, triethylene_glycol
- Unit operations
- ContactorLetdown2× Regen
Opens live on the canvas — free, no install.
Explore the model & flowsheetFrequently asked questions
- What does the TEG natural gas dehydration model simulate?
- Wet natural gas is contacted counter-currently with lean triethylene glycol (TEG) in an absorber, pulling water vapor into the glycol to meet a pipeline water spec; the rich glycol is then let down in pressure and regenerated in two flashes — the first flashes off the bulk of the co-absorbed methane, the second (hot) flash boils the absorbed water off the now nearly gas-free glycol, leaving hot lean glycol bottoms (its recycle back to the absorber is reported as a product, the same open-loop simplification used elsewhere in this library). Water is the most common undesirable natural-gas impurity — it forms hydrates that plug valves and fittings once the gas is compressed or cooled.
- Is "TEG natural gas dehydration" the same as a glycol dehydration unit?
- Yes — this model covers what is also called glycol dehydration unit, TEG dehydration, natural gas dehydration unit. It runs the real process on the rigorous solver, so you can size and study it directly.
- Which thermodynamic method does it use?
- The PENG-ROBINSON property package, over methane, water, triethylene_glycol — already selected. You can switch the method on the canvas before running.
- Which unit operations are in the flowsheet?
- It chains Contactor, Letdown, 2× Regen. Every block is a real, solvable unit operation you can reconfigure, add to, or remove.
- Do I need to install software or buy a license?
- No. TEG natural gas dehydration runs entirely in your browser on MaximaLabs — free, no install, no license. Open the model to load it live and run the deterministic solver.
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Perry Ch.13 Example 2: lean-oil absorber
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Perry Ch.13 Example 5: two-step absorber with intercooling
Two absorption stages in series with intercooling between them (removing the heat of absorption, which otherwise raises K-values and hurts recovery) to maximize LPG recovery, from Chapter 13 of Perry's Chemical Engineers' Handbook.
Acetone from isopropanol dehydrogenation
Endothermic gas-phase dehydrogenation of isopropanol (IPA) to acetone, after Luyben (Ind. Eng. Chem. Res. 2011, 50, 1206). The H₂-rich reactor off-gas is scrubbed with water to recover the acetone before venting, then a column splits acetone from the water/unreacted-IPA absorbent.
CO2 removal from syngas (Rectisol-style physical solvent)
A CO₂-laden syngas stream from gasification/reforming (H₂/CO with 25% CO₂, the actual Rectisol duty — scrubbing raw syngas ahead of methanol/ammonia synthesis, not treating pipeline natural gas) is sweetened by a cold-methanol physical-solvent absorber (chosen because chemical amine reactions aren't modeled here) down toward synthesis-loop spec, then the rich solvent is regenerated by a pressure letdown into a second flash that flashes the bulk of the absorbed CO₂ back off — the same letdown-valve-plus-flash regeneration pattern used for HDA's and methanol synthesis's own dissolved-gas trains. No solvent recycle loop (an honest simplification: the regenerated solvent is reported as a product stream rather than closed back onto the absorber feed). From the ChemSep casebook (CO₂ removal from natural gas), adapted to Rectisol's real syngas duty.
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.