Solvent Selection for H2S and Mercaptan Scrubbing in Cracked LPG Streams

Cracked LPG streams derived from fluid catalytic cracking, delayed coking, visbreaking, and steam cracking present a sulfur distribution dominated by hydrogen sulfide and low-molecular-weight mercaptans. A representative FCC LPG stream can contain 10–5000 ppmw H₂S and 10–1000 ppmw mercaptan sulfur, but published data for any specific refinery configuration is limited and must be established through sampling per ASTM D5623 or ASTM D5504. The immediate processing objective is not solely total sulfur reduction; H₂S and mercaptans must be removed to different endpoints because they behave differently in downstream product specifications. H₂S in LPG is quantified by lead acetate staining methods such as ASTM D2420 or ISO 8819, and mercaptan sulfur is often determined by potentiometric titration per ASTM D3227 after pressure sampling. Copper strip corrosion testing per ASTM D1838 is sensitive to both H₂S and elemental sulfur, and a product LPG stream intended for petrochemical feedstock frequently requires a copper strip classification of 1a or better and total sulfur below 30 mg/kg. Fuel-grade LPG may tolerate higher total sulfur but still requires control of odor and corrosivity. The selection of a scrubbing solvent therefore depends on the relative concentrations of H₂S, methanethiol, ethanethiol, propanethiol, carbonyl sulfide, and carbon disulfide in the cracked LPG, as well as the degree of olefin co-absorption that can be tolerated in the treating train. Hydrogen sulfide is a weak diprotic acid and reacts readily with aqueous bases, but mercaptans are significantly weaker acids and require either strong caustic or physical solvation. This difference explains why a single solvent is rarely sufficient for simultaneous deep removal of H₂S and mercaptans from cracked LPG without careful optimization of solvent composition, contactor design, regeneration energy, and corrosion control.

Thermodynamic and Kinetic Constraints in Aqueous Alkanolamine Treating

The selection of an aqueous alkanolamine solvent for cracked LPG begins with acid-base equilibrium and liquid-liquid distribution. Hydrogen sulfide exhibits a first pK_a near 7.0, methanethiol near 10.3, ethanethiol near 10.6, and tertiary amine MDEA near 8.6. The proton-transfer reaction between H₂S and MDEA is thermodynamically favorable, whereas proton transfer from methanethiol to MDEA is not sufficiently favorable to yield deep mercaptan extraction in a single equilibrium stage. Primary and secondary amines such as monoethanolamine and diethanolamine have higher pK_a values near 9.5 and 8.9 respectively, but the equilibrium advantage over a tertiary amine is still insufficient for mercaptan removal to trace levels. Consequently, mercaptan removal in an amine-only system depends on physical solubility, which is low in aqueous solutions and decreases with increasing temperature. Published data for specific distribution coefficients of methyl mercaptan between cracked LPG and aqueous 45 wt% MDEA at 15 barg and 40 °C is limited, and vendor equilibrium models should be calibrated against pilot liquid-liquid extraction data before design. The chemical reaction between H₂S and MDEA is rapid enough that liquid-film mass transfer controls absorption at industrial contactor conditions; carbonyl sulfide hydrolysis, by contrast, is slower and often limits deep desulfurization when the cracked LPG contains significant COS. Aqueous alkanolamine solvents are therefore selected primarily for H₂S removal, with mercaptan removal treated as a secondary benefit only when mercaptan concentrations are low. The solvent concentration, lean loading, and contactor staging can be manipulated to increase H₂S capacity, but the maximum mercaptan extraction remains constrained by unfavorable equilibrium. This constraint explains why many cracked LPG treating trains are split into a regenerative amine section for bulk H₂S removal followed by a caustic or Merox section for mercaptan removal.

In liquid-liquid extraction service, the cracked LPG is contacted with aqueous amine in a vertical countercurrent contactor, typically a packed column or sieve-tray column fitted with coalescing internals. The contactor operates at a pressure sufficient to maintain LPG in the liquid phase, commonly 10–20 barg, with a lean amine temperature of 35–50 °C. A lean amine temperature below the LPG feed temperature can condense water into the hydrocarbon phase and cause downstream freeze or water carryover; a lean amine temperature more than 5 °C above the LPG feed can increase hydrocarbon co-absorption and amine foaming. Rich amine from the contactor is let down through a flash drum to remove dissolved light hydrocarbons, filtered through 5 µm cartridge filters and a side-stream activated carbon bed, then heated in a plate-and-frame or shell-and-tube lean/rich exchanger to a regenerator inlet temperature of 110–125 °C. The regenerator is a packed or trayed column operating at 1.5–2.0 bar g, with stripping steam or reboiler vapor supplying the reduction in acid gas partial pressure required to regenerate the solvent. Lean amine leaving the regenerator is cooled to contactor temperature and returned to the extraction column. The LPG product leaves the top of the contactor through a water wash section and coalescer to reduce amine and water carryover. In cracked LPG service, the contactor internals may require additional fouling resistance because diolefins and heavy sulfur species can polymerize on metal surfaces when temperatures exceed 50 °C. The use of structured packing with high open area and low liquid holdup, combined with periodic solvent filtration, is a common equipment strategy to maintain mass transfer efficiency.

Does Caustic Addition Outperform Regenerative Solvents for Mercaptan Removal?

Aqueous sodium hydroxide at 10–15 Baumé, approximately 8–12 wt% NaOH, reacts irreversibly with both H₂S and mercaptans. The stoichiometry for H₂S absorption is H₂S + 2NaOH → Na₂S + 2H₂O, and for methanethiol the reaction is CH₃SH + NaOH → CH₃SNa + H₂O. The high base strength of caustic shifts the equilibrium strongly toward mercaptide formation, giving extraction efficiencies for methyl mercaptan in excess of 90% in a well-designed liquid-liquid contactor. Caustic extraction is therefore selected when cracked LPG contains mercaptan concentrations that would otherwise require excessively tall amine contactors or when the product specification is driven by total sulfur rather than H₂S alone. The spent caustic stream is hazardous and requires oxidation or neutralization before discharge; in many refineries, the spent caustic is routed to a Merox oxidation unit to regenerate sodium hydroxide for reuse. The caustic system removes H₂S and mercaptans non-selectively, and the consumption of caustic by H₂S is a critical economic limitation because every mole of H₂S consumes 2 moles of NaOH. Cracked LPG feeds containing high H₂S relative to mercaptans therefore incur high caustic make-up rates unless a separate amine unit removes H₂S first. The operating pH in the caustic contactor is typically above 13, which also initiates base-catalyzed reactions with reactive olefins and carbonyl compounds if present. The resulting polymeric residues can accumulate at the hydrocarbon-water interface and create emulsion layers that reduce separation efficiency. Process control therefore includes continuous monitoring of spent caustic pH, sulfide alkalinity, and mercaptide alkalinity, with online analyzers calibrated to laboratory titrations per ASTM D4052 for density and in-house methods for alkalinity. The presence of excess caustic in the treated LPG is controlled by a downstream water wash and coalescing media with pore sizes from 0.3 µm to 5 µm, because sodium carryover can damage downstream catalyst beds or cause salt deposition in reboilers.

Mercaptan oxidation in spent caustic is carried out in a continuous Merox extraction unit using a fiber-film contactor to achieve high interfacial area per unit volume. In the contactor, LPG flows as the continuous phase while caustic is distributed over a bundle of stainless steel fibers, forming a thin aqueous film. This design reduces caustic holdup and improves mass transfer compared with stirred or trayed contactors because the characteristic diffusion path is less than 100 µm in the film. The rich caustic is mixed with air and passed through a fixed-bed oxidation reactor containing a sulfonated cobalt phthalocyanine catalyst dispersed on activated carbon. Mercaptides are oxidized to disulfides, which are immiscible and are removed by coalescing. The oxidation air rate is controlled to maintain a stoichiometric excess of 1.2–1.5 times the mercaptide concentration to avoid over-oxidation to sulfates. Reactor outlet temperature is typically held below 55 °C to limit catalyst leaching and control peroxide formation. The air injection must be carefully regulated because excess oxygen can promote gum formation in the cracked LPG and increase spent caustic chemical oxygen demand. Regenerated caustic is returned to the extraction section, and a small purge stream is discharged to prevent accumulation of sodium sulfide, thiosulfate, sulfate, and high-boiling polymer. The purge stream usually requires post-treatment by wet air oxidation or biological oxidation before discharge. Published data for specific cracked LPG fiber-film contactor performance is limited, but commercial licensors provide design correlations based on caustic alkalinity, fiber surface area, contactor diameter, and LPG flow per fiber bundle area.

Hybrid Physical-Chemical Solvents and Olefin Co-Absorption Constraints

Sulfolane-based hybrid solvents such as Sulfinol-D combine a physical solvent for mercaptans and COS with a chemical solvent for H₂S. A common formulation contains 35–45 wt% sulfolane, 35–45 wt% diisopropanolamine or methyldiethanolamine, and 10–15 wt% water. The sulfolane component provides a high distribution coefficient for methyl and ethyl mercaptans by van der Waals and dipole interactions; the aqueous amine component reacts with H₂S. The resulting solvent can achieve simultaneous H₂S and mercaptan removal in a single train, but co-absorption of propylene and butene is significant because sulfolane is a good solvent for light olefins. Absorbed hydrocarbons are liberated in the regenerator flash and can overload the regenerator overhead condenser unless the rich solvent is flashed at an intermediate pressure of 3–6 bar g upstream of the main stripper. Published field data for cracked LPG liquid-liquid extraction with Sulfinol-D is limited; most documented applications involve high-pressure natural gas and refinery off-gas treating, where solvent viscosity and hydrocarbon co-absorption are lower. For cracked LPG, the design must include a hydrocarbon recovery section that separates flashed propylene and butenes from the flash gas before sending acid gas to sulfur recovery. The rich solvent flash drum must also be designed for three-phase separation because water, hydrocarbon, and solvent phases can form. The solvent circulation rate depends on the mercaptan distribution coefficient, which increases with decreasing temperature and increasing sulfolane content. However, higher sulfolane content raises solvent viscosity and reduces mass transfer in liquid-liquid contactors. A pilot contactor with 24 helical static mixer elements followed by a coalescer is often used to generate droplet dispersion and measure actual extraction efficiency before full-scale design.

When physical solubility mechanisms dominate, the extraction capacity for mercaptans increases as temperature decreases and pressure increases. For a liquid-phase LPG contactor, cooling the feed to 5–15 °C improves mercaptan distribution into the solvent but also increases hydrocarbon co-absorption and may promote hydrate formation if free water is present. Dimethyl ethers of polyethylene glycol, commonly referred to as Selexol, have high mercaptan solubility and are used in gas treating; however, high viscosity at low temperature and strong olefin co-absorption make them less suitable for cracked LPG liquid-liquid extraction. Published data for this specific configuration is limited, and pilot testing is required before commercial application. The choice between a hybrid solvent and a caustic/Merox system is therefore governed by the disposable spent caustic logistics, the presence of COS and CS₂, and the allowable hydrocarbon loss. Hybrid solvents offer regeneration and lower chemical consumption, but require higher initial capital investment and more complex solvent management. In cracked LPG service, the olefin co-absorption penalty may exceed the benefit of regenerative mercaptan removal when propylene and butylene are high-value petrochemical feeds. A detailed techno-economic comparison must account for solvent losses through thermal and oxidative degradation, make-up water, antifoam addition, filter replacement, and hydrocarbon recovery compression.

When Corrosion Boundaries and Regeneration Energies Overlap

Carbon steel in wet H₂S service is susceptible to sulfide stress cracking and hydrogen-induced cracking. Pressure vessels, piping, and exchangers exposed to amine solutions containing H₂S must comply with NACE MR0175/ISO 15156-2, with weld hardness limits typically below 22 HRC and postweld heat treatment applied to reduce residual stress. The regenerator reboiler and overhead accumulator are common corrosion zones because hot lean amine containing residual H₂S and carbon dioxide can dissolve protective iron sulfide films. Corrosion rates in lean amine above 120 °C can accelerate when heat-stable amine salts exceed 1.0 wt% as amine, although published data for specific cracked LPG units varies. Heat-stable salts formed by reaction with organic acids, oxygen, and sulfur dioxide are controlled with a slipstream reclaimer and activated carbon bed. Caustic systems present a different corrosion profile: carbon steel is generally acceptable at moderate temperatures up to 50 °C, but stress corrosion cracking can occur in hot caustic service above 80 °C, particularly at high hydroxide concentrations. For this reason, hotter sections of the Merox oxidation reactor and caustic regenerator often use stress-relieved carbon steel or stainless steel with appropriate chloride limits. The overlap between corrosion control and regeneration energy is most severe in amine reboilers, where higher regeneration temperatures improve lean acid gas loadings but also increase corrosion, amine degradation, and energy consumption. The selection of regenerator pressure is therefore a compromise: a lower pressure reduces reboiler temperature but increases stripping steam demand and acid gas compression load, while a higher pressure reduces gas compression but increases reboiler temperature and corrosion risk.

Degradation of alkanolamines in cracked LPG service is influenced by dissolved oxygen, COS, and CS₂. Primary and secondary amines form heat-stable salts and oxazolidinones with COS; tertiary amines are more resistant but still degrade slowly via ring-opening reactions with CO₂ and oxygen. An oxygen scavenger and nitrogen blanketing of storage tanks limits oxidative degradation. Rich amine filtration with 5–10 µm particulate filters protects the regenerator from fouling; a side-stream carbon bed at 10–15% of circulation removes dissolved hydrocarbons and surface-active degradation products that cause foaming. Foaming episodes in trayed regenerators can be mitigated by maintaining a flash drum residence time of 20–30 minutes at 0.5–1.0 bar g and by limiting lean amine surface tension above 55 dyn/cm through degradation control. In caustic systems, mercaptide oxidation catalyst life is shortened by hydrogen sulfide carryover into the oxidation reactor because sodium sulfide consumes caustic and can precipitate iron. Therefore, the caustic extraction section is often staged so that fresh caustic contacts the low-H₂S LPG after a first caustic stage removes bulk H₂S. The spent caustic from the first stage is purged, and the second stage caustic is regenerated in the Merox reactor. This staged configuration reduces catalyst poisoning and sodium sulfate formation but requires additional settling vessels and pumps. Operational data from refinery caustic systems show that water content in the caustic must be controlled between 75% and 85% to balance viscosity and mercaptide solubility; published data for cracked LPG-specific systems is limited.

Continuous monitoring of cracked LPG sulfur species at the contactor outlet uses gas chromatography with sulfur-selective detection per ASTM D5623 or ASTM D5504. For mercaptan speciation, a sulfur chemiluminescence detector provides low parts-per-million detection. Total sulfur in the product is measured by wavelength-dispersive X-ray fluorescence per ASTM D2622, and copper strip corrosion per ASTM D1838 is performed after water wash and coalescing. H₂S breakthrough is monitored by lead acetate tape analyzers calibrated to ASTM D2420. The analytical frequency during solvent changeover is increased to every 4 hours for sulfur speciation and every 2 hours for H₂S until stable operation is confirmed. In addition, solvent quality is monitored for lean amine loading, heat-stable salt content, chloride content, and organic acid content using in-house methods that are often correlated to ASTM D664 acid number titration. The test data are used to adjust reclaimer feed rate, antifoam injection, and anti-corrosion chemical addition. The compliance checklist below summarizes the standards most frequently applied to cracked LPG solvent selection and product verification.

Regenerator overhead acid gas from cracked LPG amine treating contains H₂S and minor mercaptans. The overhead gas is sent to sulfur recovery, typically a Claus unit, where the H₂S to CO₂ ratio and mercaptan content affect combustion and catalytic stages. The presence of mercaptans in acid gas can raise the combustion air demand and require a higher flame temperature to ensure destruction; sulfur recovery units fed with high mercaptan acid gas may need a tail gas treating absorber using 35–50 wt% MDEA or a selective oxidation catalyst. Process control includes online H₂S and SO₂ analyzers at the Claus tail gas stack, with sulfur recovery efficiency required to meet 99.9% or higher depending on local permits. The solvent selection decision for cracked LPG H₂S and mercaptan scrubbing is therefore coupled to the sulfur recovery unit capacity, treating gas compression requirements, and spent caustic disposal infrastructure. In practice, cracked LPG treatment trains frequently combine an aqueous amine H₂S absorber, a caustic mercaptan extraction stage, and Merox oxidation rather than relying on a single solvent. This staged configuration allows each solvent to operate within its thermodynamic and kinetic strength while avoiding the excessive equipment cost and operating risk associated with using a physical or hybrid solvent for the entire sulfur load. Published operating data for specific cracked LPG configurations is limited, but the general selection logic is well established in refinery treating practice and in vendor design manuals for amine, caustic, and Merox systems. The operational boundaries for each solvent, including caustic strength, amine concentration, contactor temperature, regenerator pressure, filter size, and corrosion monitoring frequency, must be defined before detailed engineering and validated during pilot or field demonstration.