Technology Type

Definition and Purpose

The Saturated Gas Plant (SGP) — also referred to as a Gas Concentration Unit (GCU) or refinery gas recovery plant — is the central light-ends recovery facility that processes the combined off-gases and unstabilized hydrocarbon liquids from refinery units producing paraffinic (olefin-free) light hydrocarbons. Its feeds originate principally from the crude and vacuum distillation units (CDU/VDU), hydrotreaters (naphtha, diesel, VGO), hydrocrackers including mild hydrocracking configurations, solvent deasphalting (SDA) units, and catalytic reformers.

The plant's function is threefold:
(1) recover valuable C₃⁺ hydrocarbons (LPG and naphtha) from streams that would otherwise be downgraded to fuel gas
(2) reject light ends (C₁/C₂, hydrogen) to the refinery fuel gas system or hydrogen recovery
(3) deliver specification-grade intermediate products — stabilized naphtha and sweetened LPG — to downstream treating, blending, or petrochemical feedstock pools.

The plant is termed "saturated" because its feed streams contain essentially no olefins, in contrast to the unsaturated (cracked) gas plant serving the FCC and other conversion units, which handles olefin-rich gases and incorporates olefin recovery facilities such as propane-propylene superfractionators. Segregating the two gas plants allows each to be optimized independently: olefin recovery economics on the cracked side, and simple, robust LPG/naphtha recovery on the saturated side — a configuration increasingly favored in petrochemical-integrated refinery complexes.

Feed Sources and Characteristics

Process Configuration

1. Feed Knockout and Segregation

Incoming off-gases arrive at widely varying pressures and are first routed through feed knockout drums to remove entrained liquid hydrocarbons and water. The condensed liquids join the unstabilized naphtha stream for stabilization. High-pressure hydrotreater and hydrocracker off-gases are segregated from low-pressure distillation overheads to optimize the compression scheme.

2. Wet Gas Compression

Low-pressure streams are boosted to absorber operating pressure (typically 10–15 bar) by multi-stage reciprocating or centrifugal compressors — usually two to three stages with interstage cooling and knockout drums between stages to remove condensed hydrocarbons and water progressively. High-pressure off-gases are introduced directly into the absorber or an appropriate compressor stage, minimizing compression energy. Compressor design for saturated service is straightforward, as the absence of diolefins eliminates the polymerization fouling risks that complicate cracked-gas compressor operation.

3. Primary Absorber

The combined compressed gas flows to the primary absorber, where C₃⁺ components are absorbed into a circulating lean oil — typically unstabilized naphtha from the crude unit or debutanizer bottoms from within the plant itself. The absorber is equipped with intercoolers to remove the heat of absorption, which is essential to maximizing recovery: propane-plus recovery of 90–95% or better is typical. Tray or packed internals are conventional; no special metallurgy or fouling-resistant design is required in saturated service.

4. Stripper (C₂ Rejection)

The rich oil from the absorber base is sent to a stripper column, where co-absorbed ethane and lighter components are rejected overhead and recycled to the absorber feed or routed to fuel gas. This step is critical to product quality: residual ethane in the recovered LPG must be minimized to meet commercial LPG vapor pressure specifications (and cracker feed quality requirements in integrated complexes).

5. Sponge Absorber

The lean gas leaving the primary absorber passes through a secondary sponge absorber, where it is contacted with a heavier circulating oil (hydrotreated heavy naphtha or kerosene-range material) to recover entrained lean oil and naphtha vapors. This prevents gasoline-range hydrocarbon losses to the fuel gas system. The resulting dry gas — methane, ethane, and hydrogen — leaves the plant to the refinery amine system for H₂S removal, then to the fuel gas header, a hydrogen recovery unit (PSA/membrane), or the steam cracker.

6. Debutanizer

The rich liquid (absorbed C₃⁺ plus naphtha carrier) is fractionated in the debutanizer:

• Overhead: mixed C₃/C₄ saturated LPG, routed to the treating sequence.
• Bottoms: stabilized (debutanized) naphtha with controlled Reid Vapor Pressure, routed to the naphtha hydrotreater, gasoline pool, or cracker feed depending on refinery configuration.

7. Optional LPG Splitting

Where segregated propane and butane products are required — for example, dedicated propane and butane cracker furnace feeds (which give different ethylene yields and may be cracked in segregated coils), butane supply to alkylation or isomerization, or commercial propane/butane product blending — a depropanizer or C₃/C₄ splitter follows the debutanizer.

8. Associated Treating Systems

The recovered saturated LPG undergoes the standard two-step treating sequence:

• Amine treating (liquid-liquid contactor with MDEA or DEA): removes H₂S to <10 ppm and CO₂, producing amine-treated LPG. Mercaptans are largely unaffected at this stage.
• Caustic sweetening (Merox): extracts and oxidizes mercaptans, producing sweetened LPG meeting copper strip corrosion (1a/1b) and sulfur specifications, followed by water washing and drying where petrochemical feedstock quality (cracker feed: typically <1 ppm S, low moisture) is required.

Because the LPG is fully saturated, it can proceed directly to steam cracker furnaces after sweetening — unlike cracked LPG, which requires selective hydrogenation to remove diolefins and olefin management before such use.

Product Slate and Destinations

Distinction from the Unsaturated (Cracked) Gas Plant

Role in the Integrated Refinery–Petrochemical Complex

In a petrochemical-oriented complex, the saturated gas plant assumes strategic importance as the consolidation point for premium cracker feedstocks. The saturated LPG it recovers — fully paraffinic, sulfur-free after treating, and free of reactive contaminants — is an ideal steam cracker feed delivering high ethylene yields. Likewise, stabilized full-range naphtha from mild hydrocracking operations can be routed unsplit to the cracker, avoiding splitter capital and energy costs. By concentrating light-ends recovery from the crude distillation and hydrotreating block in a single optimized facility, the SGP maximizes liquid yield, minimizes fuel gas downgrading, and provides the feed flexibility that underpins the refinery–cracker integration philosophy.

Typical Equipment List

1. Feed Receiving and Separation

2. Compression

3. Absorption and Stripping Section

4. Debutanizer / Fractionation Section

5. Heat Exchange and Utilities

6. Treating Tie-Ins (adjacent, often integrated)

7. Safety, Relief and Drainage

8. Instrumentation and Control

Typical equipment count for a mid-size SGP (2–4 MMTPA crude-equivalent):

~3–4 columns, 1–2 compressor trains, 8–12 heat exchangers/coolers, 6–10 drums/vessels, 10–15 pump sets — compact relative to primary process units, but central to refinery light-ends economics.