Gas Treating & Contaminant Removal

1. The contaminants & their specs

Raw gas carries acid gases (H₂S, CO₂), water, mercury, and sometimes sulfur species (COS, mercaptans). Pipeline/sales specs are tight: H₂S typically ≤ ¼ grain/100 scf (≈ 4 ppmv), CO₂ ≤ ~2 mol%, water ≤ 7 lb/MMscf, and — for plants feeding aluminium cryogenic exchangers — mercury to the sub-microgram-per-Nm³ level. Each contaminant has its own removal unit, sequenced ahead of the cryogenic recovery it would otherwise damage.

2. Amine acid-gas removal

The dominant acid-gas removal process is amine absorption: a regenerable aqueous alkanolamine (MEA, DEA, or selective MDEA) absorbs H₂S/CO₂ in a contactor and is stripped in a regenerator. The key sizing parameter is the circulation rate set by the acid-gas loading:

with MDEA chosen for H₂S-selective service (slip CO₂), and the regenerator reboiler duty roughly proportional to the acid gas stripped (~per-kmol heuristic for screening). Selectivity, loadings and contactor stages are confirmed in a rate-based simulator (ProMax/HYSYS).

3. Acid-gas injection (AGI)

Where Claus sulfur recovery is uneconomic (small or remote streams), the concentrated acid gas off the amine regenerator is compressed and injected into a deep disposal formation. The design centres on multistage compression (with interstage cooling and dehydration to avoid hydrate/corrosion), the discharge pressure to exceed formation/fracture pressure, and material selection for wet acid-gas service. The compressors are specified to API 617 (centrifugal) or API 618 (reciprocating); the process basis follows the GPSA acid-gas-injection guidance — not a downstream-standard like API 685.

4. Sulfur recovery & tail gas

Larger sour streams go to a Claus sulfur recovery unit (SRU), which converts H₂S to elemental sulfur in ~94–97% recovery over 2–3 catalytic stages. To meet emission limits, a tail-gas treatment unit (TGTU) — typically the reduction-absorption SCOT process — hydrogenates all residual sulfur species back to H₂S over a Co-Mo catalyst, absorbs it in selective amine, and recycles it to the SRU front, lifting overall recovery to > 99.8–99.9%. The hydrogenation stoichiometry (SO₂ + 3H₂ → H₂S + 2H₂O; COS/Sₓ + H₂ → H₂S) sets the reducing-gas demand.

5. Mercury removal

Even trace mercury attacks brazed-aluminium plate-fin exchangers (liquid-metal embrittlement), so it is removed upstream of the cold box by a fixed adsorbent bed — non-regenerable sulfur-impregnated activated carbon or metal-sulfide (e.g. CuS) media, where Hg reacts to form stable HgS. The bed is sized by the superficial velocity (pressure-drop limit), the required mass-transfer-zone length (to guarantee outlet spec), and the total mercury loading over the design life (capacity × removal duty), which fixes the volume and replacement interval.

6. References

• GPSA Engineering Data Book (14th Ed) — §21 (Hydrocarbon Treating / amines), §22 (Sulfur Recovery & tail gas), §13 (Compressors), mercury-removal guidance.
• API STD 617 — Axial & Centrifugal Compressors; API STD 618 — Reciprocating Compressors (acid-gas injection service).
• Shell SCOT process — reduction-absorption tail-gas treatment.
• Kohl & Nielsen, Gas Purification (5th Ed) — amine, sulfur, and trace-contaminant processes.