Propylene Carbonate (Fluor Solvent) Fundamentals

1. Introduction to Propylene Carbonate

Propylene carbonate (C₄H₆O₃) is a cyclic carbonate ester used as a physical solvent for the selective removal of carbon dioxide from natural gas and industrial gas streams. Unlike chemical solvents such as amines that react with acid gases, propylene carbonate absorbs CO₂ through physical dissolution—a process governed by Henry’s Law, where the solvent’s absorption capacity increases linearly with the partial pressure of the acid gas in the feed stream.

The commercial application of propylene carbonate for gas treating is known as the Fluor Solvent Process, licensed by Fluor Corporation. First commercialized in the 1960s, the process takes advantage of propylene carbonate’s favorable physical properties: it is a single-component solvent requiring no mixing or blending, it does not degrade or produce corrosive byproducts, and it can be regenerated almost entirely by pressure reduction (flashing) rather than heat input.

Best-Suited Applications

• Bulk CO₂ removal: Feed gas containing >3–5 mol% CO₂, where large quantities of acid gas must be removed economically
• High-pressure gas streams: Operating pressures above 400 psig, where Henry’s Law provides high solvent loading and favorable economics
• Applications where H₂S removal is not the primary objective: The process has poor H₂S/CO₂ selectivity and cannot reliably achieve pipeline-quality H₂S specifications (<4 ppmv) without supplemental treatment

Propylene Carbonate Physical Properties

The extremely low vapor pressure of propylene carbonate (0.03 mmHg at 77°F) is a key advantage—solvent losses to the treated gas stream are negligible under normal operating conditions. The high boiling point (468°F) and thermal stability above 500°F mean the solvent will not decompose during normal operations, and the low freezing point (−56°F) permits cold-climate installations without freeze concerns.

2. Process Description

The Fluor Solvent Process is characterized by its simplicity. The process scheme consists of a high-pressure absorber, a series of flash drums for solvent regeneration, and a solvent circulation pump. Unlike amine systems, there is no regenerator tower, no reboiler, and no reflux condenser—regeneration is accomplished almost entirely by reducing the pressure on the rich solvent.

Absorption

Feed gas enters the bottom of a high-pressure absorber column containing 15–20 trays (valve or sieve type) or equivalent structured/random packing. Lean propylene carbonate solvent enters at the top and flows countercurrent to the gas. CO₂ dissolves into the solvent according to Henry’s Law: the higher the partial pressure of CO₂ in the gas, the more CO₂ the solvent absorbs. Operating temperatures are maintained between 60–100°F; lower temperatures favor higher solvent loading but increase viscosity.

The treated gas exits the top of the absorber with the CO₂ content reduced to the desired specification, typically 1–3 mol% for pipeline gas or lower for specific downstream requirements. The rich solvent, now loaded with dissolved CO₂, exits the bottom of the absorber and flows to the flash regeneration system.

Flash Regeneration

The rich solvent is regenerated through a series of 3 to 5 flash stages, where the pressure is reduced in steps from absorber pressure down to near-atmospheric pressure. At each stage, dissolved CO₂ evolves from the solvent as the equilibrium partial pressure drops. This multi-stage approach allows recovery of co-absorbed hydrocarbons at higher flash pressures and maximizes CO₂ release at lower pressures.

• First flash stage (high pressure): Typically 150–300 psig. Recovers dissolved hydrocarbons (methane, ethane) that can be recompressed and returned to the sales gas stream.
• Intermediate flash stages: Step the pressure down progressively. CO₂ and remaining light hydrocarbons are released.
• Final flash stage: Near atmospheric pressure (0–5 psig). Removes the majority of remaining dissolved CO₂.
• Air or nitrogen stripper: A small stripping column uses air or nitrogen to remove the last traces of dissolved CO₂ from the lean solvent before it is pumped back to the absorber. This step is optional but improves treating performance.

The key advantage of flash regeneration is that it requires only pumping energy to recirculate the solvent—no steam, no fired heater, and no thermal energy input. This gives the Fluor Solvent Process the lowest energy consumption of any commercial gas treating technology for bulk CO₂ removal.

Typical Process Conditions

3. Advantages of the Fluor Solvent Process

The Fluor Solvent Process offers several compelling advantages over chemical solvent (amine) and other physical solvent processes, particularly for bulk CO₂ removal from high-pressure gas streams.

Low Energy Consumption

Because regeneration is accomplished by flash (pressure letdown) rather than thermal stripping, the energy requirement is limited to pumping the solvent from atmospheric pressure back to absorber pressure. There is no reboiler steam consumption, no reflux condenser duty, and no fired heater. For high-pressure, high-CO₂ applications, the Fluor Solvent Process typically consumes 40–60% less energy than an equivalent amine system.

Simple Process Scheme

The equipment count is minimal: an absorber column, a series of flash drums, a circulation pump, and optionally a small air stripper. There is no regenerator tower, no reboiler, no lean/rich heat exchanger, and no reflux system. This simplicity translates to lower capital cost, reduced plot space, fewer instruments and controls, and lower maintenance requirements.

Chemical and Thermal Stability

Propylene carbonate does not react with CO₂, H₂S, or other acid gas components. It does not degrade, does not form heat-stable salts, and does not require reclaiming or solvent replacement due to degradation. The solvent is thermally stable above 500°F, far above any temperature encountered in the process.

Non-Corrosive

Unlike amine systems that require stainless steel or alloy components in the regenerator, reboiler, and lean/rich exchanger, the Fluor Solvent Process uses carbon steel construction throughout. Propylene carbonate is non-corrosive to carbon steel, even in the presence of dissolved CO₂ and H₂S. This significantly reduces equipment cost and eliminates corrosion-related maintenance.

No Foaming Problems

Foaming is a persistent operational challenge with amine systems, often caused by hydrocarbon contamination, suspended solids, or degradation products. Propylene carbonate does not foam under normal operating conditions, eliminating the need for antifoam injection, inlet filtration to the level required by amines, and troubleshooting of foaming-related capacity reductions.

Low Solvent Cost

Propylene carbonate is a widely available industrial chemical produced in large quantities. It is less expensive per gallon than specialty physical solvents such as Selexol (dimethyl ether of polyethylene glycol) and far less expensive than Rectisol (methanol at cryogenic conditions).

Energy Consumption Comparison

The trade-off is evident: the Fluor Solvent Process requires a higher solvent circulation rate (because the physical solubility of CO₂ in propylene carbonate is lower than in Selexol) but achieves dramatically lower total energy consumption. Amine systems achieve the deepest CO₂ removal but at the highest energy cost.

4. Limitations and Design Considerations

While the Fluor Solvent Process is an excellent choice for certain applications, it has specific limitations that must be understood during technology selection and process design.

Poor H₂S Selectivity

Propylene carbonate absorbs both CO₂ and H₂S, but it cannot selectively remove H₂S to pipeline specifications (<4 ppmv). The solubility of H₂S in propylene carbonate is approximately 3.5 times that of CO₂, but this ratio is insufficient for selective removal when both species are present. If H₂S removal to low concentrations is required, the Fluor Solvent Process must be followed by a polishing step (e.g., a small amine unit or iron sponge bed).

Hydrocarbon Co-absorption

Physical solvents absorb heavier hydrocarbons (C₃+) along with the acid gas. This co-absorption results in hydrocarbon losses to the flash gas unless a dedicated hydrocarbon recovery flash stage is included in the design. The first flash drum at elevated pressure (150–300 psig) is specifically designed to flash off dissolved methane and ethane for recompression and return to the sales gas. However, propane and heavier components may still be lost with the CO₂ vent stream.

Pressure Limitations

Because absorption capacity follows Henry’s Law and is directly proportional to pressure, the Fluor Solvent Process becomes uneconomical at operating pressures below approximately 300 psig. At low pressures, the solvent loading is too low to justify the high circulation rates required, and amine systems become more competitive. The sweet spot for the Fluor Solvent Process is 400–1,200 psig.

Additional Design Considerations

• Water content: Propylene carbonate is hygroscopic and absorbs water from the gas stream. Water reduces the CO₂ solubility in the solvent and increases viscosity. A water management system (molecular sieve dehydration of the lean solvent or a small water-removal flash) may be needed for wet feed gas streams.
• Solvent losses: Although the vapor pressure is very low, small solvent losses occur through mechanical carry-over from the absorber and flash drums. Mist eliminators and proper vessel internals minimize these losses. Replacement is straightforward because propylene carbonate is commercially available.
• Higher circulation rate: Compared to Selexol, propylene carbonate has a lower CO₂ solubility per unit volume. This means higher solvent circulation rates, larger pumps, and larger-diameter piping. The circulation cost is partially offset by the lower solvent unit cost.

Limitations vs. Mitigation Strategies

5. Applications and Comparison with Alternatives

Over 30 Fluor Solvent plants have been built and operated worldwide since the process was first commercialized. The technology has proven itself in a range of applications where bulk CO₂ removal at high pressure is the primary treatment objective.

Primary Applications

• Enhanced oil recovery (EOR) CO₂ removal: Produced gas from CO₂ flood operations contains 30–70% CO₂ at high pressure. The Fluor Solvent Process is well suited for bulk removal and CO₂ reinjection.
• Ammonia plant CO₂ removal: Synthesis gas in ammonia plants contains 15–25% CO₂ at 300–500 psig. Propylene carbonate removes the CO₂ efficiently with minimal energy input.
• Natural gas with high CO₂ and low H₂S: Fields producing gas with >5% CO₂ and negligible H₂S are ideal candidates, particularly at pressures above 400 psig.
• Syngas and hydrogen purification: Removal of CO₂ from synthesis gas in gasification and hydrogen production processes.

When the Fluor Solvent Process Is NOT Suitable

• H₂S must be removed to pipeline spec: Cannot achieve <4 ppmv H₂S without additional polishing treatment
• Gas pressure below 300 psig: Insufficient driving force for physical absorption; amine is more economical
• Deep CO₂ removal required: Cannot economically achieve <50 ppmv CO₂ (LNG feed specification); Selexol, Rectisol, or amine are better choices
• Feed gas with rich C₃+ content: High hydrocarbon co-absorption losses make the process less attractive for rich gas streams

When to Choose: Fluor Solvent vs. Selexol vs. Amine

Decision Summary

Choose the Fluor Solvent Process when:

• The primary objective is bulk CO₂ removal (not deep removal or H₂S treating)
• Operating pressure is above 400 psig
• Minimizing energy consumption and operating cost is a high priority
• Simple, low-maintenance operation is desired
• H₂S is absent or present only in trace quantities

For applications requiring simultaneous H₂S and CO₂ removal, deep CO₂ removal to LNG specifications, or treatment of low-pressure gas, amine (MDEA) or Selexol processes are more appropriate. In cases where the Fluor Solvent Process handles bulk CO₂ removal and a small amine polishing unit removes residual H₂S, the hybrid scheme can offer the lowest total cost for high-CO₂, moderate-H₂S feed gases.

References

1. GPSA, Chapter 21 — Hydrocarbon Treating
2. Kohl, A.L. and Nielsen, R.B., Gas Purification, 5th Edition, Gulf Publishing, 1997
3. Fluor Corporation, Fluor Solvent Process Technical Literature
4. Kidnay, A.J. and Parrish, W.R., Fundamentals of Natural Gas Processing, CRC Press, 2006