Sulfinol Process Fundamentals

1. The Hybrid Solvent Concept

The Sulfinol process is a hybrid (mixed) solvent gas treating technology that combines both physical and chemical absorption mechanisms in a single solvent system. Licensed by Shell Global Solutions, the process has been in commercial operation since the 1960s and has accumulated over 200 installations worldwide for sour gas processing, LNG feed treating, and refinery applications.

The Sulfinol solvent consists of three components: sulfolane (tetrahydrothiophene dioxide), which serves as the physical solvent; an alkanolamine (either DIPA or MDEA), which serves as the chemical solvent; and water. A typical composition is approximately 40% sulfolane, 40% amine, and 20% water by weight, although the exact proportions can be adjusted to optimize performance for a specific gas composition and treating objective.

Dual Absorption Mechanism

The chemical amine component reacts with acid gases (H₂S and CO₂) through well-known acid-base reactions, providing a baseline absorption capacity that is relatively insensitive to acid gas partial pressure. The physical sulfolane component dissolves acid gases according to Henry’s law, providing incremental absorption capacity that increases with rising acid gas partial pressure. This dual mechanism gives the Sulfinol process a significant advantage over pure amine systems when treating gases with moderate to high acid gas content.

At low acid gas partial pressures (below approximately 15–20 psia), the chemical reaction dominates and the Sulfinol solvent behaves similarly to a pure amine system. At higher partial pressures, the physical absorption contribution becomes increasingly significant, allowing higher acid gas loadings than a pure amine can achieve. This characteristic makes the Sulfinol process best suited for applications with moderate to high acid gas partial pressures, combined H₂S and CO₂ removal requirements, and the need to remove COS, CS₂, and mercaptans that pure amines handle poorly.

Sulfinol Solvent Variants

The choice between Sulfinol-D and Sulfinol-M depends primarily on whether selective H₂S removal is required. When both H₂S and CO₂ must be removed to low residual levels (e.g., LNG feed gas treating), Sulfinol-D with DIPA is preferred. When selective H₂S removal is needed to produce a rich acid gas suitable for a Claus sulfur recovery unit, Sulfinol-M with MDEA is the better choice.

2. Process Description

The Sulfinol process flow scheme is similar in layout to a conventional amine treating unit, consisting of an absorber column, rich/lean heat exchanger, regenerator column, and associated pumps and coolers. However, the process typically includes an additional flash drum between the absorber and the regenerator to recover co-absorbed hydrocarbons and flash off a portion of the physically dissolved acid gas.

Absorption Column

The absorber is a trayed or packed column with 15–25 theoretical stages, operating at the full gas delivery pressure. Sour feed gas enters at the bottom and flows upward in countercurrent contact with lean Sulfinol solvent entering at the top. Both chemical reaction and physical dissolution occur simultaneously as the gas contacts the solvent on each tray or through the packing. Because the Sulfinol solvent achieves higher acid gas loading than a pure amine, the required solvent circulation rate is typically 15–30% lower than an equivalent MDEA system, resulting in a smaller absorber diameter, smaller piping, and lower pumping energy.

Flash Regeneration

Rich solvent leaving the absorber bottom passes through a flash drum operating at an intermediate pressure (typically 50–150 psig). In this vessel, a significant fraction of the physically dissolved acid gas—particularly CO₂—flashes out of solution along with co-absorbed hydrocarbons. The flash gas may be routed to a fuel gas system, flare, or secondary treating unit depending on its composition. This flash step reduces the thermal duty on the downstream regenerator by removing bulk acid gas without requiring heat input.

Thermal Regeneration

After flashing, the rich solvent is heated in a rich/lean heat exchanger and fed to the regenerator column. Steam stripping in the regenerator drives off the remaining chemically bound acid gas from the amine component and any residual physically dissolved acid gas from the sulfolane. The regenerator operates at near-atmospheric pressure with a reboiler temperature of approximately 250–270°F. The overhead acid gas is routed to a Claus sulfur recovery unit or incinerator.

Hydrocarbon Co-absorption

The sulfolane component of the solvent has a significant affinity for heavier hydrocarbons, particularly aromatics (BTEX) and C₃+ paraffins. This co-absorption causes hydrocarbon losses from the treated gas and can lead to BTEX emissions at the regenerator overhead. The flash drum upstream of the regenerator is essential for recovering co-absorbed hydrocarbons before they enter the regenerator and are released with the acid gas.

Typical Operating Parameters

3. Advantages Over Pure Amine Systems

The Sulfinol process offers several compelling advantages over conventional amine treating systems, particularly when acid gas partial pressures exceed approximately 50 psia or when removal of COS, CS₂, and mercaptans is required. These advantages translate directly into smaller equipment, lower operating costs, and broader treating capability.

Key Advantages

• Higher acid gas loading: The physical absorption component allows rich solvent loadings of 0.5–1.2 mol acid gas per mol amine, compared to 0.4–0.55 mol/mol for pure MDEA. This directly reduces the required solvent circulation rate.
• Smaller equipment: Lower circulation rates translate to smaller absorber diameters (10–20% reduction), smaller piping, smaller pumps, and reduced plot space requirements.
• Lower pumping energy: With 15–30% less solvent to circulate, pump power consumption decreases proportionally, reducing long-term operating costs.
• Lower regeneration energy per mole of acid gas: The physically dissolved fraction of the acid gas can be recovered by pressure reduction (flashing) rather than thermal regeneration, reducing the overall steam or reboiler duty per unit of acid gas removed.
• COS, CS₂, and mercaptan removal: Pure amine systems are generally poor at removing carbonyl sulfide, carbon disulfide, and mercaptans. The sulfolane physical solvent component provides significant absorption capacity for these species, achieving 80–95% removal depending on operating conditions.
• Lower corrosion potential: At equivalent acid gas removal duty, the Sulfinol solvent operates at lower amine loading per unit volume (because sulfolane carries part of the acid gas load), which tends to reduce corrosion rates in carbon steel equipment compared to heavily loaded pure MDEA systems.

Performance Comparison: 500 MMSCFD Gas Treating

The following table compares three solvent options for treating a 500 MMSCFD natural gas stream containing 5% CO₂ and 1% H₂S at 900 psig:

The comparison illustrates that Sulfinol-M offers a favorable balance between the low hydrocarbon losses of pure MDEA and the high acid gas capacity of a physical solvent like Selexol. It is particularly attractive when COS and mercaptan removal is required alongside H₂S and CO₂ treating, a combination that pure MDEA cannot effectively achieve.

4. Design Considerations and Limitations

While the Sulfinol process offers significant performance advantages, engineers must account for several design considerations and limitations that differentiate it from conventional amine systems. Proper attention to these factors during the design phase ensures reliable long-term operation.

Critical Design Factors

Solvent Cost: Sulfolane is considerably more expensive than common amines such as MDEA or DEA. The initial solvent inventory represents a significant capital expenditure, and ongoing make-up costs for sulfolane losses must be included in operating cost estimates. Typical sulfolane make-up rates are 0.5–2.0 lb per MMSCF of gas treated, depending on solvent management practices.

Hydrocarbon Co-absorption: The physical solvent component absorbs heavier hydrocarbons, leading to product losses and potential BTEX emissions at the regenerator. For rich gas streams containing significant C₃+ hydrocarbons, hydrocarbon losses can be 0.5–2.0% of the feed gas heating value. The flash drum is essential for recovering these hydrocarbons, but some losses are unavoidable.

Solvent Degradation: Sulfolane can undergo thermal and oxidative degradation over time, forming acidic byproducts that increase corrosion rates and reduce solvent effectiveness. A solvent reclaiming system (typically vacuum distillation or thermal reclaiming) is required to remove degradation products and maintain solvent quality. Reclaiming is typically performed on a slipstream basis.

Foaming: The Sulfinol solvent is generally less prone to foaming than pure amine systems due to the surface-tension-modifying effect of sulfolane. However, foaming can still occur in the presence of liquid hydrocarbons, corrosion inhibitors, or suspended solids. Standard anti-foam practices (inlet separation, carbon filtration, mechanical filtration) should be incorporated in the design.

Material Compatibility: Standard carbon steel construction is acceptable for Sulfinol systems, consistent with conventional amine plant practice. Stainless steel cladding is used in areas of highest corrosion potential (regenerator overhead, reboiler tubes) following the same guidelines as MDEA systems.

Limitations and Mitigation Strategies

5. Applications and Selection Criteria

The Sulfinol process occupies a unique position in the gas treating technology landscape, bridging the gap between pure chemical (amine) solvents and pure physical solvents. Proper technology selection requires understanding where each solvent type excels and where it falls short.

When to Use Sulfinol

• Acid gas partial pressure exceeds 50 psia: At higher partial pressures, the physical absorption component provides significant incremental capacity over pure amines, reducing circulation rates and equipment size.
• COS and mercaptan removal required: If pipeline specifications or downstream process requirements demand COS removal below 5 ppmv or total sulfur specifications include mercaptans, the Sulfinol process is one of the most effective solutions available.
• Lower circulation rate desired: When plot space is constrained or pumping energy costs are high, the 15–30% circulation reduction vs. pure MDEA can be decisive.
• Combined H₂S and CO₂ removal: When both species must be removed to low levels simultaneously, the hybrid solvent handles the combined duty efficiently.

When Sulfinol Is Not Ideal

• Very low acid gas content: When acid gas partial pressures are below 15–20 psia, the physical absorption contribution is minimal and a conventional amine system is simpler and more cost-effective.
• Hydrocarbon loss is unacceptable: For lean gas treating where every BTU of product gas must be preserved, the hydrocarbon co-absorption inherent in the sulfolane component may be economically prohibitive.
• Operational simplicity is paramount: The Sulfinol process requires solvent reclaiming, flash drum operation, and solvent quality management that add complexity compared to a simple MDEA system.
• Very small plants: The licensing costs and solvent inventory expense are harder to justify for small facilities treating less than approximately 50 MMSCFD.

Common Applications

With over 200 installations worldwide, the Sulfinol process has been proven in a wide range of gas treating applications:

• Sour gas processing: Treating high-pressure sour natural gas with significant H₂S and CO₂ content in upstream gas plants
• LNG feed treating: Meeting the stringent acid gas and total sulfur specifications required for cryogenic liquefaction (<50 ppmv CO₂, <4 ppmv H₂S, <10 ppmv total sulfur)
• Refinery off-gas treating: Removing H₂S, COS, and mercaptans from refinery fuel gas and process gas streams
• Syngas treating: Removing acid gases from synthesis gas in ammonia, methanol, and hydrogen production facilities

Technology Selection Guide

The technology selection decision should be based on a detailed techno-economic evaluation that considers feed gas composition, product specifications, acid gas disposal options, plot space constraints, utility costs, and total life-cycle cost including solvent make-up and licensing fees. In many cases, the Sulfinol process delivers the lowest total cost of ownership for medium-to-large gas treating facilities operating at moderate to high acid gas partial pressures with COS/mercaptan removal requirements.

References

1. GPSA, Chapter 21 — Hydrocarbon Treating
2. Shell Global Solutions — Sulfinol Process Technical Literature
3. Kohl, A.L. and Nielsen, R.B., Gas Purification, 5th Edition, Gulf Publishing
4. Kidnay, A.J. and Parrish, W.R., Fundamentals of Natural Gas Processing, CRC Press