Amine System Foaming Fundamentals

1. What is Amine Foaming?

Amine foaming is the formation of a stable foam layer on the trays or packing surfaces within an amine absorber or regenerator column. This foam layer disrupts normal gas–liquid contact, severely reducing the mass transfer efficiency required for H₂S and CO₂ removal from natural gas and refinery fuel gas streams. Foaming is the single most common operational problem in amine gas treating plants and is responsible for a significant portion of unplanned throughput reductions and off-spec gas events.

Under normal operating conditions, gas bubbles through the amine solution on each tray, creating a froth zone where acid gas absorption occurs. This normal frothing is inherently unstable—bubbles form, rise, and burst within seconds, maintaining a dynamic liquid surface that promotes efficient mass transfer. Foaming, in contrast, produces a persistent layer of small, stable bubbles that resist coalescence and collapse. The foam can occupy the entire space between trays, blocking gas flow passages and causing liquid to be entrained upward with the gas (amine carry-over) or to be pushed down through the downcomers (flooding).

Symptoms of Amine Foaming

• Differential pressure increase: A sudden or sustained rise in ΔP across the absorber or regenerator tray section is the most reliable early indicator of foaming. The foam occupies tray volume that would otherwise be available for gas flow.
• Amine carry-over: Foam entrains amine droplets into the treated gas outlet, leading to amine losses and contamination of downstream equipment (dehydration units, pipelines, compressors).
• Poor H₂S/CO₂ removal: The foam barrier reduces effective gas–liquid contact area, causing acid gas breakthrough and off-specification treated gas.
• Erratic level control: Foam in the column sump creates false level readings. Displacer-type level instruments interpret the foam as liquid, causing control valve instability and potential overfilling or draining of the column sump.
• High amine losses: Carry-over into the outlet gas and mechanical losses from level control upsets can increase amine consumption by 2–10 times normal rates.

Impact on Treating Capacity

Foaming can reduce the effective treating capacity of an amine unit by 30–80%, depending on severity. In severe cases, operators must reduce gas throughput to prevent complete column flooding, resulting in production deferrals and revenue loss. The downstream consequences can be equally significant: amine carry-over fouls dehydration glycol, contaminates compressor oil, and accelerates corrosion in carbon steel pipelines.

Foaming Severity Classification

It is important to distinguish between foaming and hydraulic flooding. Hydraulic flooding is caused by operating above the column’s design capacity (excessive gas or liquid rates) and is resolved by reducing throughput. Foaming occurs at or below normal operating rates and is caused by contaminants that stabilize bubble films. Both produce similar ΔP symptoms, but the root causes and corrective actions differ fundamentally.

2. Causes of Foaming

Amine foaming is caused by surface-active agents that reduce the surface tension of the amine solution, stabilizing bubble films and preventing their normal coalescence and rupture. Clean amine solutions have a surface tension of approximately 45–55 dynes/cm and do not foam under normal contactor conditions. When contaminants reduce the surface tension below approximately 30–35 dynes/cm, the solution becomes increasingly foam-prone.

Contaminants in Feed Gas

The feed gas entering the amine absorber is the most common source of foaming contaminants:

• Liquid hydrocarbons: Condensate, lube oil mist, and heavy hydrocarbon vapors are the most frequent cause of amine foaming. Even trace quantities (5–50 ppm) of liquid hydrocarbons can cause severe foaming because they act as powerful surfactants at the gas–liquid interface.
• Well-treating chemicals: Corrosion inhibitors, scale inhibitors, and foaming agents used in well stimulation and production operations are designed to be surface-active and readily cause amine foaming when they carry over into the gas stream.
• Compressor oils: Reciprocating compressor lubricating oil carry-over introduces hydrocarbon-based surfactants directly into the gas. Synthetic compressor oils are generally less problematic than mineral oils but can still cause foaming.
• Pipeline corrosion inhibitors: Filming-type corrosion inhibitors used in upstream gathering systems are highly surface-active and are a common cause of foaming at gas plant inlet treating units.
• Glycol carry-over: If a glycol dehydration unit is upstream of the amine unit, glycol droplets or vapor can contaminate the amine solution and contribute to foaming.

Amine Degradation Products

Over time, amine solutions degrade through reactions with CO₂, O₂, and thermal exposure, producing contaminants that promote foaming:

• Heat-stable salts (HSS): Formed when strong acids (formic, acetic, oxalic, thiosulfuric, thiocyanic) react with amine to create salts that cannot be regenerated by normal stripping. HSS above 1.0–2.0 wt% increases solution viscosity and surface activity, promoting foaming.
• Organic acids: Formic and acetic acids from CO₂-amine degradation reactions lower solution pH and increase corrosion rates, generating suspended solids that further stabilize foam.
• Iron sulfide particles: Corrosion of carbon steel equipment in the presence of H₂S produces fine iron sulfide (FeS) particles that accumulate in the amine solution. These particles concentrate at bubble surfaces and mechanically stabilize the foam film.

Suspended Solids

Fine solid particles are particularly effective foam stabilizers because they migrate to the gas–liquid interface and create a mechanical barrier that prevents bubble coalescence:

• Iron sulfide (FeS): The most common suspended solid in amine systems; generated by corrosion of carbon steel piping, vessels, and heat exchangers
• Iron oxide (Fe₂O₃): Forms during shutdowns when the system is exposed to air; converts to FeS when H₂S is reintroduced
• Filter media fines: Degraded filter cartridges can release cellulose or polymer fibers into the amine circulation loop
• Activated carbon fines: Improperly designed or maintained carbon beds can release carbon particles downstream

Operating Errors

• High gas velocity: Operating the absorber above its design gas velocity increases the froth height and can push an otherwise marginal system into foaming
• Rapid pressure changes: Sudden pressure reductions cause dissolved gases to flash out of solution, creating a burst of small bubbles that can trigger foam formation
• Temperature excursions: High lean amine temperatures reduce surface tension and increase the foam tendency of the solution

Common Foaming Causes, Sources, and Prevention

3. Foaming Detection and Testing

Early detection of foaming tendency is essential to prevent operational upsets. A combination of on-line process monitoring and periodic laboratory testing provides the most reliable approach to managing foam risk in amine systems.

On-Line Indicators

Operators should monitor the following process parameters for early signs of foaming:

• Tray ΔP trending: Install differential pressure transmitters across the absorber and regenerator tray sections. A sustained ΔP increase of 10% or more above baseline at constant gas and liquid rates indicates developing foam. Trending ΔP over time (daily or per-shift) is more informative than spot readings.
• Level control stability: Erratic behavior of the absorber sump or regenerator sump level controller—particularly rapid oscillation or inability to maintain setpoint—often indicates foam in the column sump interfering with level measurement.
• Amine losses: A sudden increase in amine makeup requirements without an identifiable leak suggests carry-over losses due to foaming. Track amine inventory weekly and correlate with gas throughput.
• Treated gas quality: Rising H₂S or CO₂ in the treated gas at constant operating conditions indicates reduced mass transfer efficiency, potentially caused by foam reducing the effective tray contact area.

Foam Test (Bottle Shake Test)

The simplest and most widely used field test for foaming tendency is the bottle shake test, which compares the foam behavior of the operating amine solution against a fresh reference sample:

1. Collect a 200–250 mL sample of operating lean amine solution in a clean glass bottle
2. Prepare an equal volume of fresh amine solution at the same concentration as a reference
3. Seal both bottles and shake vigorously for 15–20 seconds using the same technique
4. Set both bottles on a flat surface and immediately observe the foam height
5. Record the time for the foam to break completely (foam break time)
6. Compare the operating sample against the fresh reference

The operating sample should produce similar or less foam than the fresh reference. If the operating sample generates significantly more foam or the foam persists longer, contaminants are present and corrective action is warranted.

Modified ASTM Foam Test

For more quantitative results, laboratories use a modified version of ASTM D 892 adapted for amine solutions. In this test, a controlled volume of nitrogen or air is sparged through the amine sample at a standardized rate, and the foam height and break time are measured under reproducible conditions. This method provides better repeatability than the bottle shake test and allows trending of foam tendency over time.

Interfacial Tension Measurement

Interfacial tension (IFT) measurement provides a direct indication of surfactant contamination in the amine solution. Clean amine solutions typically exhibit surface tension values of 45–55 dynes/cm. As surface-active contaminants accumulate, the surface tension decreases. General guidelines:

• >40 dynes/cm: Low foaming risk; solution is relatively clean
• 30–40 dynes/cm: Moderate foaming risk; contaminants accumulating; increase monitoring frequency
• <30 dynes/cm: High foaming risk; corrective action required (filtration, carbon treatment, or reclaiming)

Heat-Stable Salt Analysis

Total heat-stable salt (HSS) concentration is determined by titration or ion chromatography. HSS levels provide an indicator of overall amine degradation and help guide reclaiming decisions:

• <1.0 wt%: Normal; routine monitoring sufficient
• 1.0–2.0 wt%: Elevated; plan reclaiming during next turnaround
• >2.0 wt%: High; schedule reclaiming promptly; increased foaming and corrosion expected

Foam Test Interpretation

4. Foaming Prevention and Mitigation

Effective foam management requires a multi-layered approach that addresses contaminant removal, solution quality maintenance, and proper operating practices. The goal is to prevent contaminants from entering and accumulating in the amine system rather than relying solely on antifoam chemicals to mask the symptoms.

Inlet Separation

Proper inlet gas separation is the first and most important line of defense against foaming. The inlet scrubber or separator upstream of the amine absorber must effectively remove liquid hydrocarbons, free water, and entrained solids from the feed gas:

• Size the inlet separator for adequate residence time (minimum 3–5 minutes liquid retention)
• Install a high-efficiency mist eliminator (vane pack or mesh pad) rated for droplet removal down to 10 μm
• Provide liquid dump control with high-level alarm to prevent liquid carry-over during slug events
• Consider a coalescing filter downstream of the separator for feed gas streams with persistent aerosol contamination

Filtration

The amine solution filtration system removes suspended solids and dissolved hydrocarbons from the circulating amine. A properly designed filtration system includes both mechanical and adsorptive elements:

• Mechanical filter (10 μm): A cartridge or bag filter on a slipstream (10–20% of circulation rate) or full-flow basis removes iron sulfide, iron oxide, and other solid particles. Replace filter elements when ΔP reaches 15–20 psi or on a scheduled basis.
• Activated carbon filter: A fixed bed of granular activated carbon downstream of the mechanical filter adsorbs dissolved hydrocarbons, well-treating chemicals, and other organic contaminants. Size the carbon bed for a minimum contact time of 15–20 minutes at the design flow rate. Replace the carbon when breakthrough is detected by rising foam tendency.

The mechanical filter must always be upstream of the activated carbon bed to prevent solid particles from plugging the carbon and reducing its adsorptive capacity.

Anti-Foam Agents

Anti-foam agents (also called defoamers) are surface-active chemicals that destabilize foam by disrupting the thin liquid films that form bubble walls. They are an important short-term tool for managing foaming events but should not be relied upon as a permanent solution. Excessive or continuous antifoam use can itself cause problems, including emulsification, fouling of carbon beds, and interference with level instruments.

Dosage: Typical antifoam dosage is 5–50 ppm based on amine circulation rate. Start at the low end (5–10 ppm) and increase as needed. Overdosing can actually increase foaming tendency.

Injection point: Inject antifoam into the lean amine line upstream of the absorber. For regenerator foaming, inject into the rich amine line upstream of the regenerator. Continuous low-dose injection is preferred over intermittent high-dose batch treatment for systems with chronic foaming.

Anti-Foam Types Comparison

Reclaiming

When heat-stable salts and degradation products accumulate beyond acceptable levels, the amine solution requires reclaiming to restore its quality:

• Thermal reclaiming: A slipstream of amine solution is heated in a reclaimer vessel to boil off clean amine and water, leaving behind HSS, degradation products, and heavy contaminants as a residue. Most commonly used with MEA and DGA systems. MDEA cannot be thermally reclaimed due to its high boiling point.
• Ion exchange: Strong-base anion exchange resins remove HSS anions (formate, acetate, oxalate, thiosulfate) from the amine solution, regenerating the amine in the process. Applicable to all amine types including MDEA.
• Electrodialysis: An emerging technology that uses ion-selective membranes and an electric field to remove HSS from amine solutions. Lower waste generation than thermal reclaiming.

Operating Practices

• Amine concentration: Maintain the design amine concentration. Over-concentrated solutions have higher viscosity and lower surface tension, increasing foam tendency. Under-concentrated solutions require higher circulation rates, increasing gas velocity through the trays.
• Circulation rate: Avoid over-circulation. Excessive amine flow increases tray liquid loading and froth height, pushing the system closer to the flooding limit. Operate at the minimum circulation rate that achieves the required treating specification.
• Temperature control: Maintain lean amine temperature 10–15°F above the inlet gas temperature to prevent hydrocarbon condensation in the absorber. Avoid excessively high lean amine temperatures (>140°F), which reduce surface tension and increase foam tendency.
• Reboiler duty: Control reboiler temperature to prevent amine degradation. Maximum recommended reboiler temperatures: MEA 260°F, DEA 250°F, MDEA 260°F, DGA 280°F.

5. Best Practices for Foam-Free Operation

Achieving reliable foam-free operation requires a systematic approach that integrates proper facility design, disciplined operating procedures, and proactive maintenance practices. The following guidelines represent industry best practices drawn from GPSA recommendations and operational experience across hundreds of amine treating facilities.

Design Considerations

• Inlet separator: Size for worst-case slug conditions with a high-efficiency mist eliminator (vane-type or wire mesh, rated for ≤10 μm droplet removal). Include a boot or liquid accumulation section with high-level shutdown.
• Filtration capacity: Design the mechanical filter system for full-flow operation at minimum, with duplex filters to allow online cartridge changeout. Size the activated carbon bed for 15–20 minutes of contact time at the full amine circulation rate.
• Carbon bed placement: Install the activated carbon bed downstream of the mechanical filter and upstream of the lean amine cooler. A properly placed carbon bed removes dissolved organics before they enter the absorber.
• Absorber tray design: Select tray types with lower foam sensitivity. Valve trays with larger valve openings and deeper downcomers are generally less susceptible to foaming than sieve trays. Structured packing is more sensitive to foam than trays due to smaller flow channels.
• Flash tank: Install a rich amine flash tank between the absorber and the rich/lean exchanger to release dissolved hydrocarbons before they reach the regenerator. Flash tank pressure should be 50–75 psig.

Operational Monitoring Program

• Foam testing: Conduct bottle shake tests on lean amine samples at least monthly, or weekly during periods of changing feed gas composition. Compare results against fresh amine baseline and track the trend.
• HSS monitoring: Analyze lean amine for total heat-stable salts quarterly. Initiate reclaiming when HSS exceeds 1.0–1.5 wt% for MEA/DEA or 2.0 wt% for MDEA.
• Filter ΔP tracking: Log mechanical filter differential pressure daily. Frequent filter changes (more than weekly) indicate excessive solids loading and warrant investigation of the corrosion source.
• Amine analysis program: Quarterly comprehensive amine analysis should include: amine concentration, acid gas loading, HSS composition, total iron, suspended solids, and surface tension.
• Absorber ΔP trending: Record absorber and regenerator tray ΔP each shift at constant operating conditions. Establish baseline values and set alarm points at 10–15% above baseline.

Maintenance Practices

• Filter element changes: Replace mechanical filter cartridges before ΔP exceeds 15–20 psi or on a scheduled basis (typically every 1–4 weeks depending on solids loading)
• Carbon bed changeout: Replace activated carbon when foam testing indicates rising foam tendency despite good mechanical filtration. Typical carbon bed life is 6–18 months depending on contaminant loading.
• Corrosion monitoring: Install corrosion coupons in the hot rich amine piping and regenerator overhead. Excessive corrosion rates (>5 mpy) generate iron sulfide that contributes to foaming.
• Turnaround inspections: During planned shutdowns, inspect absorber trays for fouling, plugged downcomers, and damaged tray components. Inspect the inlet separator internals and replace the mist eliminator if damaged.

Troubleshooting Approach

When foaming is suspected, follow this systematic approach to identify and correct the root cause:

1. Confirm foaming: Verify that the ΔP increase is due to foaming (occurs at or below design rates) rather than hydraulic flooding (occurs only at high rates). Collect a lean amine sample for foam testing.
2. Apply antifoam: Inject antifoam at 10–20 ppm to provide immediate relief while investigating the root cause. If antifoam provides relief, foaming is confirmed.
3. Check inlet separation: Verify that the inlet separator is functioning properly. Check for high liquid levels, damaged mist eliminator, or liquid carry-over. Sample the inlet gas for hydrocarbon content.
4. Check filtration: Verify mechanical filter ΔP and carbon bed condition. Replace filter elements and carbon if overdue. Check for filter bypass valves left open.
5. Analyze amine quality: Send lean amine sample for comprehensive analysis including HSS, total iron, suspended solids, and surface tension. High HSS or iron indicates degradation; low surface tension confirms surfactant contamination.
6. Review upstream changes: Investigate any recent changes in feed gas source, upstream chemical injection programs, or well operations that could introduce new contaminants.
7. Implement corrective action: Based on the identified root cause, implement the appropriate long-term fix (improved inlet separation, carbon bed replacement, reclaiming, upstream chemical change, etc.).

Foam Prevention Checklist

References

1. GPSA, Chapter 21 — Hydrocarbon Treating
2. Kohl, A. L. and Nielsen, R. B., Gas Purification, 5th Edition, Gulf Publishing, 1997
3. Lieberman, N. P., Troubleshooting Natural Gas Processing, PennWell, 1987
4. Dow Chemical Company, Gas Conditioning Fact Book