Process History

Absorption of hydrocarbons from gas into a liquid oil is one of the oldest gas-processing technologies:

• Early 1900s–1920s: First applied in the natural gasoline industry (USA) to recover heavier hydrocarbons (“casinghead gasoline”) from associated gas, replacing earlier compression and condensation methods. Early plants used “absorption oil” (typically a naphtha cut) in bubble-cap tray columns.

• 1930s–1950s: Widespread adoption for natural gasoline and LPG recovery; integration into refinery saturated gas plants to recover C₃⁺ from FCC and coker off-gases. The concept of the “sponge absorber” emerged in refinery FCC units.

• 1960s onward: Cryogenic turboexpander processes progressively displaced lean oil absorption for high ethane recovery (>70–90% C₂) in gas processing, because absorption alone achieves only modest ethane recovery at practical oil circulation rates.

• Today: Lean oil absorption remains the standard technology in refinery gas concentration/recovery units (FCC, delayed coker, hydrocracker off-gas treatment) for C₂/C₃⁺ recovery, and for moderate ethane recovery where cryogenics is not economically justified.

Process Summary

Lean oil absorption is a physical separation process in which a gas stream is contacted counter-currently with a low-volatility hydrocarbon liquid (“lean oil” or “sponge oil” — typically heavy naphtha, kerosene, or light gas oil, MW ~100–200). Heavier gas components (C₂⁺, primarily C₃⁺) dissolve preferentially into the oil. The “rich oil” is then regenerated by distillation (stripper/deethanizer), recovering the absorbed components as products, and the regenerated “lean oil” is recycled.

Main applications:

• Recovery of LPG (C₃/C₄) and naphtha from refinery fuel gas (FCC, coker, reformer off-gas)

• Moderate ethane recovery for petrochemical feedstock

• NGL recovery from natural gas (legacy/ moderate-recovery plants)

Chemistry / Thermodynamic Basis

• No chemical reaction occurs — the mechanism is physical solubility governed by vapor-liquid equilibrium.

• Absorption of component i is described by the equilibrium K-value: K_i = y_i / x_i, a function of temperature, pressure, and oil properties.

• The Kremser equation (Kremser, 1930) governs theoretical-stage absorption performance: recovery of a component increases with the absorption factor A = L/(K·V) (liquid/gas ratio relative to K-value).

• Key principles:

  • Lower temperature → lower K-values → better absorption

  • Higher pressure → better absorption

  • Heavier lean oil (lower volatility) → lower oil loss to overhead gas, but higher circulation needed

  • Absorption is exothermic (heat of solution); intercooling improves recovery.

Step-by-Step Process Description

Typical refinery application (coker/FCC wet gas with ethane recovery):

Step 1 — Gas Compression & Cooling

• Wet gas compressed in a multi-stage centrifugal/reciprocating wet gas compressor to 10–20 bar(g)

• Interstage cooling with knockout drums removes condensed liquids

• Final discharge cooled to 30–40 °C (air/water cooling); refrigerated cooling to ~5–15 °C where higher recovery is needed

Step 2 — H₂S Removal (Amine Treating)

• Fuel gas and liquid streams treated with MDEA/DEA amine to <~10–50 ppmv H₂S before product recovery (protects product specs and downstream metallurgy)

Step 3 — Primary Absorber

• Compressed gas enters the bottom of the absorber (trayed or packed column, typically 20–40 theoretical stages including presaturator sections)

• Lean sponge oil introduced at the top; typical L/G ratio set so absorption factor A ≈ 1.2–1.4 for the target key component

• Intercoolers (pump-around circuits) remove heat of absorption

• Overhead: treated fuel gas (H₂, CH₄, N₂, residual C₂) to refinery fuel system or to a secondary sponge absorber

Step 4 — Sponge (Secondary) Absorber (refinery configuration)

• Fuel gas overhead contacts a heavier oil (LCO/light cycle oil or coker gas oil) to recover entrained primary sponge oil — minimizing oil losses

Step 5 — Rich Oil Handling / Stripper (Deethanizer)

• Rich oil preheated by lean/rich exchangers, fed to a stripper or deethanizer column (typically 20–30 trays)

• Reboiler duty supplied by steam or hot oil; column overhead at conditions yielding C₂ product (deethanizer overhead) or C₃⁺ product depending on configuration

• Typical deethanizer: pressure 15–30 bar, overhead temp ~−10 to 40 °C, reboiler 120–200 °C (values vary strongly with design; confirm against licensor data)

Step 6 — Product Fractionation

• Depropanizer (C₃ overhead), debutanizer (C₄/naphtha split) as required

Step 7 — Lean Oil Regeneration & Recycle

• Stripped oil cooled (against rich oil, then air/water), a slipstream purged to control heavies buildup, makeup oil added; recycled to absorber top

Typical Operating Envelope

Process Performance

Confirmed literature values:

• Propane recovery: typically 80–95% achievable in conventional lean oil absorption

• Ethane recovery: typically 20–50% at economic circulation rates; >70% generally requires cryogenics (turboexpander)

• Butanes⁺ recovery: >95–99%

• Lean oil losses: minimized by sponge section; typically small fraction of circulation rate (makeup required)

• Selectivity: non-selective physical equilibrium — light ends (H₂, CH₄) largely unabsorbed; residual methane in rich oil stripped in deethanizer

Economic Performance

Publicly available, technology-specific CAPEX/OPEX figures for lean oil absorption are scarce. Established qualitative economics from multiple sources are:

• CAPEX: Lower than cryogenic turboexpander plants of equivalent capacity (no turboexpander, brazed-aluminum cold box, or deep refrigeration); major cost items are compressors, absorber/stripper columns, and heat exchange network

• OPEX: Dominated by compression power and reboiler energy for oil regeneration; lean oil makeup; amine treating utilities

• Economic crossover: For ethane recovery above ~60–70%, cryogenic processes generally show lower total cost of ownership; absorption favored for C₃⁺-only recovery and in refinery gas plants where sponge oil is available in-situ at no incremental cost

Environmental Performance

• No process emissions from chemistry (physical separation); no catalyst, no chemical reagent consumed except amine in associated treating

• Emissions sources: compressor drivers (gas turbines/engines → NO_x, CO₂), fugitive VOC emissions from valves/flanges (managed under LDAR programs), oil purge stream (typically returned to refinery pool)

• Energy intensity: moderate; heat integration (lean/rich exchange) standard practice

• Positive environmental role: reduces refinery flaring by recovering valuable hydrocarbons; enables fuel-gas quality control (H₂S removal upstream)

Proprietary Technologies, Providers & Licensors

Lean oil absorption is largely a mature, non-proprietary technology; however, licensors offer proprietary optimized gas-plant designs incorporating it:

References

1. Gas Processors Suppliers Association (GPSA) — Engineering Data Book, 14^th Edition (2017) — Sections 5 (Relief systems) & absorption design fundamentals

2. John M. Campbell & Co. — Campbell R.N. (Ed.), Gas Conditioning and Processing, Vol. 1 & 2, 9^th Ed. (2014) — Absorption design and lean oil selection

3. Gulf Professional Publishing / Elsevier — Mokhatab S., Poe W.A., Mak J.Y., Handbook of Natural Gas Transmission and Processing, 4^th Ed. (2018) — NGL recovery via absorption vs. cryogenics

4. Kremser A. (1930), “Theoretical Analysis of Absorption Process,” National Petroleum News (May 21, 1930) — Foundational Kremser absorption equation

5. Wiley — Kidnay A.J., Parrish W.R., Fundamentals of Natural Gas Processing, 2^nd Ed. (2011) — Lean oil absorption vs. turboexpander comparison

6. Honeywell UOP — FCC Gas Recovery / Saturated Gas Plant Solutions — Accessed for product portfolio context

7. Lummus Technology — Refinery Technology Portfolio — Gas concentration unit offerings

8. GPA Midstream Association — Technical publications on NGL recovery processes

9. Wikipedia — Natural-gas processing (accessed Sep 2026) — Overview of absorption vs. cryogenic NGL recovery