Module 4
Gas Processing & Treatment
Raw gas straight off the well is dirty, wet, and corrosive — it would plug, eat through, or under-fuel the pipeline. A processing plant is the car wash and quality-control gate that turns that raw mix into clean, dry, safe "pipeline-quality" gas.
What you'll be able to do
- Explain why raw gas isn't pipeline-ready — water, acid gases, and excess heavy ends.
- Match each problem to its fix: dehydration, amine sweetening, and NGL recovery.
- Name the key numbers — water at
4–7 lb/MMscf, H₂S near4 ppm, gas at950–1,050 Btu/scf. - Respect the deadliest hazard on site: H₂S toxicity, including why your nose stops warning you.
- Read a fractionation train and a pipeline-quality spec table.
Three big jobs — dry it, sweeten it, and right-size the heavy ends — then check it against the tariff.
Why raw gas isn't ready
Picture the stream arriving from the gathering system as a damp, slightly sour cocktail: mostly methane, but carrying water vapor, acid gases, and a load of heavier hydrocarbons. Each of those causes a specific failure if it reaches the transmission line. The plant exists to fix all three before the gas is handed off.
The three core jobs of a gas plant, in the order most plants run them.
Water → plugs & rust
Water vapor freezes into ice-like hydrates that plug the line, and liquid water plus acid gas forms acids that corrode steel from the inside.
Acid gases → corrosion
Hydrogen sulfide (H₂S) and carbon dioxide (CO₂) are acid gases. They attack the pipe and, in H₂S's case, are acutely lethal to people.
Heavy ends → wrong fuel
Too many heavier hydrocarbons (NGLs, natural gas liquids) can blow past the heating-value and dewpoint spec, so they're recovered and sold separately.
🧭 The big idea
"Pipeline quality" isn't one thing — it's a checklist. Dry enough, sweet enough, and the right energy content. Miss any one and the gas is rejected at the city gate.
Dehydration — taking the water out
Drying the gas is usually the first conditioning step. The workhorse is glycol dehydration using TEG (triethylene glycol), a thirsty liquid that grabs water out of the gas. The neat part: the glycol is then reused in a loop, not thrown away.
The glycol loop. Glycol soaks up water in the contactor, then a reboiler boils that water off so the glycol can go back to work — over and over.
When a plant needs very dry gas — for example, feed to a cryogenic NGL unit that runs near −100 °F — glycol alone isn't enough. Those plants use molecular sieves, solid beds that adsorb water down to trace levels so nothing freezes in the cold section.
Why obsess over a little water? Because the gas is about to enter a high-pressure transmission line — and hydrates form precisely at high pressure + low temperature. Pull the water out here, at the low-pressure end of the gradient, and the gas can climb the pressure ladder downstream without plugging the line with ice-like solids.
🔢 Water spec — varies by climate
Treat 4–7 lb of water per MMscf (million standard cubic feet) as the typical range, not a single number. typical Warm regions tolerate up to ~7 lb/MMscf; colder regions push to ~4 lb/MMscf (and ~2–4 in Canada) because cold lines form hydrates more easily.
Sweetening — removing H₂S and CO₂
Removing acid gases is called sweetening (gas with H₂S is "sour"; clean gas is "sweet"). The standard method is amine treating: a water-based amine solution absorbs H₂S and CO₂ in a contactor, then heat regenerates it — the same absorb-and-reuse trick as glycol, but tuned for acid gases.
| Amine | Full name | Why you'd pick it |
|---|---|---|
| MEA | Monoethanolamine | Highly reactive; run dilute because it's corrosive. |
| DEA | Diethanolamine | General-purpose workhorse; very common. |
| MDEA | Methyldiethanolamine | Selective for H₂S; lower regeneration energy. |
Typical North American sales-gas acid-gas limits typical — CO₂ in particular varies; some tariffs are as strict as ~1%.
🧪 What happens to the captured H₂S?
You can't just vent it. Recovered H₂S is converted to solid, sellable sulfur by the Claus process — a thermal-plus-catalytic route (2 H₂S + 3 O₂ → 2 SO₂ + 2 H₂O, then 2 H₂S + SO₂ → 3 S + 2 H₂O). Bare Claus recovers ~95–98%; add tail-gas treating and you reach ~99%+.
H₂S safety — the deadliest number on site
Before going further, a hard stop on the most dangerous part of this whole module. H₂S ("sour gas," "rotten-egg gas") is one of the field's deadliest hazards, and its danger curve is brutally steep.
☠️ H₂S is lethal — and it disables your warning system
NIOSH IDLH = 100 ppm (IDLH = Immediately Dangerous to Life or Health). The trap: around that same ~100 ppm, H₂S paralyzes your sense of smell — the rotten-egg odor vanishes exactly when the gas turns dangerous, so "I can't smell it anymore" means worse, not safer.
At ~500 ppm a person can collapse within minutes; at ~700–1,000 ppm, death can come in one or two breaths. This is why sour-gas sites mandate fixed H₂S monitors, escape breathing apparatus, and constant wind-direction awareness.
🔢 Exposure numbers, low to high
PEL (Permissible Exposure Limit, OSHA General Industry): 20 ppm ceiling, 50 ppm 10-minute peak. IDLH: 100 ppm — also where smell fails. ~500 ppm: collapse in minutes. ~700–1,000 ppm: fatal in a breath or two.
ℹ️ A common mix-up
The often-quoted "10 ppm TWA / 15 ppm STEL" is the ACGIH guideline (and the vacated 1989 limit), not the enforceable OSHA General Industry PEL. Sources conflate these constantly — when it matters, cite the PEL above.
NGL recovery & fractionation
The heavier hydrocarbons — NGLs (natural gas liquids: ethane, propane, butanes, pentanes-plus) — are valuable on their own, and pulling the right amount out is also how the plant hits the gas's heating-value and dewpoint spec. The modern recovery method is deep cold.
A cryogenic turboexpander plant chills the gas to roughly −100 °F or colder, condensing the NGLs out as liquid. A demethanizer column then strips residual methane back into the sales-gas stream, so you don't lose your main product to the liquids.
The mixed NGL liquid is then split into pure products in a fractionation train — distillation towers in series, each named for the lightest component it takes off the top, with the heaviest left at the bottom:
Mixed NGLs
│
▼
Demethanizer ──► Deethanizer ──► Depropanizer ──► Debutanizer ──► Butane splitter
(returns CH4 (takes C2 (takes C3 (takes C4 (iso- vs
to sales gas, ethane) propane) butanes) normal-butane)
not a product)
│
▼
Pentanes-plus (natural gasoline)
left at the bottom
Light off the top, heavy at the bottom. Each tower removes the next-lightest cut; pentanes-plus ("natural gasoline") drops out last.
🔗 Think of it like a sorting line
The train is a series of sieves with progressively bigger holes. The lightest molecule escapes first; each later tower catches the next size up, until only the heaviest "natural gasoline" remains at the very end.
Go deeper: the oil side — stabilization & LACT optional
Stabilization. Crude from the separator still holds light ends (C₁–C₄) that would flash off in a storage tank — a fire hazard and lost product. A stabilizer removes those light ends, lowering volatility measured as RVP (Reid Vapor Pressure, ASTM D323 at 100 °F). Stabilized crude is typically targeted below ~10 psi RVP (range ~8–12 psi; tanker cargo is stricter).
LACT unit. The LACT (Lease Automatic Custody Transfer) skid is the automated point that meters, samples, and transfers crude off the lease — recording net volume and quality (BS&W = Basic Sediment & Water, plus API gravity). It's the "cash register" of upstream oil: the custody-transfer point where your production becomes someone else's inventory.
The pipeline-quality spec
A transmission pipeline's tariff sets exactly what it will accept. The values below are typical, but every line is different — read the tariff, because each parameter varies.
| Parameter | Typical pipeline-quality spec | Fixed by |
|---|---|---|
| Heating value (HHV) | ~950–1,050 Btu/scf | NGL recovery / blending |
| Water content | ~4–7 lb/MMscf | Dehydration |
| H₂S | ≤ ~4 ppm (0.25 grain/100 scf) | Amine sweetening |
| CO₂ | ≤ ~2–3 mol% | Amine sweetening |
| Temp · dewpoint · O₂ · inerts | per tariff | Varies |
Each value varies by tariff. HHV bands can run up to ~1,150 Btu/scf on some lines.
Key takeaways
- Three jobs: dehydrate (water), sweeten (acid gases), recover NGLs (heavy ends) — then the gas meets spec.
- Dehydration: TEG glycol contactor with regeneration; molecular sieves for cryo feed. Water spec
4–7 lb/MMscf, varies by climate. - Sweetening: amine treating (MEA / DEA / MDEA); H₂S ≈
4 ppm, CO₂ ~2–3% (varies). Recovered H₂S → sulfur via Claus. - H₂S is lethal: IDLH
100 ppmalso kills your sense of smell; ~700–1,000 ppm fatal in a breath or two. - NGL train order: demethanizer → deethanizer → depropanizer → debutanizer → butane splitter; pentanes-plus at the bottom.
- The spec is a tariff: gas ~
950–1,050 Btu/scf; every limit varies by pipeline.
Why must water be removed from raw gas before it enters the pipeline?
Why: Water vapor freezes into hydrate plugs, and liquid water plus H₂S/CO₂ forms corrosive acids — the two reasons dehydration comes first.
A plant uses TEG in a contactor, then heats it in a reboiler before reusing it. What is TEG doing?
Why: TEG (triethylene glycol) is the standard glycol dehydration solvent — it grabs water, then regeneration drives the water off so it can be reused. Amines handle acid gas; cryo handles NGLs.
You're on a sour-gas site and the rotten-egg smell suddenly fades. What's the safest interpretation?
Why: Around 100 ppm (the NIOSH IDLH) H₂S deadens olfactory nerves, so the warning odor disappears exactly when the gas turns deadly. Losing the smell is a danger signal.
Which is the correct order of towers in an NGL fractionation train?
Why: Each tower takes the next-lightest component off the top, lightest first — so methane, then ethane, propane, butanes, and finally the butane splitter — leaving pentanes-plus at the bottom.
A raw-gas sample reads 30 ppm H₂S against a ~4 ppm spec. Which process fixes it?
Why: H₂S and CO₂ are acid gases removed by amine treating; the recovered H₂S is then converted to elemental sulfur in the Claus process. Dehydration handles water; cryo handles NGLs.