Amine Inlet Separation Fundamentals

1. Why Inlet Separation is Critical

Feed gas entering an amine absorber is rarely clean. The gas stream arriving from upstream gathering systems, compressors, or process units often carries a range of contaminants: liquid hydrocarbons, compressor lube oils, free water, solid particulates (iron sulfide, mill scale, sand), and pipeline corrosion products. If these contaminants reach the amine contactor, the consequences are severe and costly.

Liquid hydrocarbons are the single most damaging contaminant. Even trace quantities—as low as a few ppmv of condensed hydrocarbons—can trigger amine foaming, which reduces absorber capacity, causes carryover of amine into the treated gas, and can shut down the treating operation entirely. Compressor oils, particularly synthetic lubricants, are equally problematic because they accumulate in the amine solution and are difficult to remove once introduced.

Solid particulates cause a different class of problems. Iron sulfide and corrosion products act as surfactants that stabilize foam, accelerate amine degradation through heat-stable salt formation, and promote erosion and fouling of heat exchangers, trays, and packing. These particles also plug filters prematurely, increasing maintenance costs and amine losses.

Economic Impact of Foaming

The cost of a single foaming event can be substantial. Lost production from reduced throughput, off-spec gas penalties from pipeline operators, amine losses due to carryover, and equipment damage from liquid slugging can easily reach tens of thousands of dollars per event. Chronic foaming can cost a facility hundreds of thousands of dollars annually in lost efficiency, chemical costs, and unplanned shutdowns. Proper inlet separation is the first and most effective line of defense—far more reliable than antifoam injection or downstream filtration alone.

Contaminant Sources and Impact on Amine System

Proper inlet separation is widely regarded as the single most important equipment design decision in an amine treating facility. Industry experience consistently shows that plants with well-designed inlet separation systems operate with fewer foaming events, lower chemical costs, and higher on-stream availability than those that rely on downstream remediation.

2. Inlet Scrubber Sizing

The inlet scrubber (also called inlet knockout drum or inlet separator) is a vertical pressure vessel located immediately upstream of the amine absorber. Its purpose is to remove bulk liquids and entrained droplets from the feed gas before the gas enters the contactor. The vertical knockout drum is the most common configuration for amine inlet service because it provides efficient gravity separation, accommodates mist elimination devices, and has a relatively small footprint.

Gas Capacity: Souders-Brown Equation

The maximum allowable gas velocity through the scrubber is determined by the Souders-Brown equation, which balances the upward gas drag force against the downward gravitational settling force on liquid droplets:

Where V_max is the maximum superficial gas velocity (ft/s), K is the design constant (ft/s), ρ_L is the liquid density (lb/ft³), and ρ_V is the gas density at operating conditions (lb/ft³). For vertical vessels equipped with a wire mesh mist eliminator, the K factor is typically 0.167 ft/s. Without a mist eliminator, the K factor is reduced to approximately 0.10–0.12 ft/s to account for the larger minimum droplet size that can be removed by gravity alone.

The minimum vessel diameter is then calculated from the gas volumetric flow rate and the maximum allowable velocity:

Liquid Capacity and Holdup

The liquid section of the scrubber must provide adequate holdup volume to handle slug flow conditions and normal liquid accumulation. For amine inlet service, a minimum liquid retention time of 3–5 minutes is recommended, based on the maximum expected liquid rate. The holdup volume must account for slug volumes from upstream pigging operations, compressor liquid dumps, and process upsets.

The vessel length-to-diameter (L/D) ratio for vertical scrubbers typically ranges from 3:1 to 5:1. The gas disengagement section above the inlet nozzle and the liquid sump below the inlet both contribute to the overall vessel height. The mist eliminator is located in the upper portion of the vessel, typically 12–18 inches below the gas outlet nozzle.

Scrubber Sizing Guidelines

The governing diameter is the larger of the gas-capacity diameter and the liquid-capacity diameter. In most amine inlet applications, the gas velocity governs the vessel size, but liquid holdup should always be checked, particularly for services with high liquid-to-gas ratios or slug flow potential.

3. Mist Elimination Technology

Even after bulk liquid removal by gravity in the inlet scrubber, the gas stream still contains fine liquid droplets (mist) that are too small to settle under gravity at the prevailing gas velocity. These droplets range from sub-micron aerosols to droplets of 100 μm or larger. Mist eliminators are installed inside the scrubber to capture these fine droplets and coalesce them into larger drops that drain back to the liquid sump.

Wire Mesh Demister Pads

Wire mesh demisters are the most common and cost-effective mist elimination device. They consist of a pad of knitted wire (typically 304 or 316 stainless steel) with a thickness of 4–6 inches. Gas flows upward through the mesh, and droplets impact the wire surfaces, coalesce, and drain downward. Standard wire mesh pads effectively remove droplets larger than approximately 10 μm in diameter, with a typical collection efficiency of 99% for droplets in that size range. The pressure drop across a wire mesh pad is low, typically 0.5–1.0 inches of water column (WC).

Vane-Type Mist Eliminators

Vane-type (or chevron) mist eliminators consist of a series of corrugated plates that force the gas stream through multiple changes of direction. Liquid droplets, having greater inertia than the gas, impact the vane surfaces and are collected in drainage channels. Vane-type units are better suited for services with high liquid loads because they are less prone to flooding and plugging than wire mesh. They effectively remove droplets larger than approximately 15–20 μm, with pressure drops of 1–3 inches WC.

Coalescing Elements

Coalescing filter elements use fine fiber beds (typically glass or polymer fibers) to capture sub-micron liquid aerosols. Gas passes through the fiber bed, and tiny droplets are captured by Brownian diffusion, interception, and inertial impaction. The captured droplets coalesce within the fiber bed and drain as larger drops from the downstream face. Coalescers can remove droplets as small as 0.3 μm with efficiencies exceeding 99.98%, making them the highest-efficiency mist elimination option. However, they have higher pressure drops (2–10 inches WC) and are significantly more expensive to purchase and maintain.

High-Efficiency Fiber Elements

High-efficiency fiber mist eliminators are a specialized category designed for fine aerosol removal in services where standard wire mesh or vane-type devices fail to provide adequate separation. These elements use engineered fiber media with controlled pore size and depth to capture aerosols in the 0.1–3 μm range. They are typically used as a secondary mist elimination stage downstream of a conventional scrubber, particularly in applications where compressor oil aerosols or fine hydrocarbon mist persistently cause amine foaming despite standard inlet separation.

Mist Eliminator Comparison

Selection of the appropriate mist elimination technology depends on the droplet size distribution in the feed gas, the liquid loading, the available pressure drop budget, and the fouling tendency of the gas. For most standard amine inlet applications, a wire mesh demister pad provides adequate protection. In services with known compressor oil carryover or fine aerosol problems, upgrading to coalescing elements or adding a secondary high-efficiency stage may be necessary.

4. Liquid Hydrocarbon Removal

Liquid hydrocarbons are the primary cause of amine foaming, and removing them to the lowest practicable level is essential for reliable amine system operation. The target is to reduce liquid hydrocarbon content in the gas entering the amine contactor to less than 1 ppmv. Achieving this target requires a combination of separation technologies and careful system design.

Coalescer Filters

Liquid-liquid coalescers and coalescer-separator vessels use fiber-bed elements to capture dispersed hydrocarbon droplets and aerosols from the gas stream. The fiber bed captures fine droplets through interception and diffusion mechanisms, then coalesces them into larger drops on the downstream face. The coalesced drops are large enough to separate by gravity in the downstream settling section. Coalescer filters are particularly effective for removing compressor oil aerosols and fine hydrocarbon mists that pass through conventional mist eliminators.

Liquid Boot or Sump

When the inlet scrubber collects both water and liquid hydrocarbons, a liquid boot (vertical extension at the bottom of the vessel) or a horizontal sump section provides gravity-based separation of the two liquid phases. The hydrocarbon layer, being lighter, floats on top of the water phase and is skimmed off through a separate nozzle. Proper interface level control between the water and hydrocarbon phases is essential for effective separation. An interface level transmitter (displacer or guided wave radar type) monitors the hydrocarbon-water boundary.

Oil Skimming

Continuous monitoring and removal of the hydrocarbon layer in the inlet separator is critical. An oil-skimming arrangement uses an adjustable weir or overflow nozzle to continuously drain the hydrocarbon layer to a slop oil system. Operators should visually inspect the skimmed liquid regularly to verify that the system is functioning and that no hydrocarbon breakthrough is occurring. Sight glasses on the liquid boot and downstream piping assist with this monitoring.

Automatic Dump Valves and Level Control

Level control on the inlet scrubber must include automatic dump valves for both the water phase and the hydrocarbon phase (if a liquid boot is used). High-level alarms (HLA) and high-high-level shutdowns (HHLA) protect the amine absorber from liquid carryover during upset conditions. The level control valve should be sized for the maximum expected liquid rate plus a safety margin for slug flow events.

Liquid Hydrocarbon Removal Methods

In many facilities, a combination of these methods is used in series: gravity separation in the inlet scrubber, mist elimination with wire mesh or coalescing elements, and activated carbon adsorption downstream of the amine system to remove any residual hydrocarbons that accumulate in the amine solution over time. The specific combination depends on the severity of the hydrocarbon contamination and the sensitivity of the amine system to foaming.

5. Design Best Practices

Effective amine inlet separation is as much about system layout and operational practices as it is about equipment selection. The following best practices are drawn from decades of industry experience and represent the consensus recommendations from GPSA, GPA, and amine technology licensors.

Location and Piping

The inlet scrubber should be located as close to the amine absorber as physically possible. Every foot of piping between the scrubber outlet and the absorber inlet is an opportunity for additional condensation, liquid accumulation, and re-entrainment. Long horizontal pipe runs between the scrubber and absorber are particularly problematic because liquid can accumulate at low points and be swept into the absorber during flow surges. When long runs are unavoidable, install drains at all low points in horizontal piping between the scrubber and the absorber.

Sizing for Maximum Flow

The inlet scrubber must be sized for the maximum expected gas flow rate, not the normal operating rate. Process upset conditions, compressor restarts, and seasonal flow variations can temporarily increase gas rates well above normal. The vessel should provide acceptable separation performance at maximum flow while maintaining stable level control during turndown. A turndown ratio of 3:1 to 4:1 is typical for amine inlet scrubbers.

Access for Inspection and Maintenance

The vessel must include adequate access for inspection and replacement of the mist eliminator. A manway or davit-served access hatch above the mist eliminator allows removal and inspection during turnarounds. Wire mesh pads in particular can become fouled with iron sulfide, hydrocarbons, or corrosion products, and visual inspection is the only reliable way to assess pad condition. Coalescing elements require periodic replacement and must be accessible without major vessel disassembly.

Instrumentation

Proper instrumentation on the inlet scrubber is essential for reliable operation and early detection of problems:

• Level indicator/transmitter: Continuous level measurement for automatic dump valve control
• High-level alarm (HLA): Warns operators of abnormal liquid accumulation
• High-high-level alarm (HHLA): Triggers shutdown or diversion to protect the absorber
• Low-level alarm (LLA): Prevents dump valve from passing gas to the liquid drain
• Pressure differential across mist eliminator: Monitors plugging; rising ΔP indicates fouling
• Pressure indicator: Monitors vessel operating pressure
• Temperature indicator: Helps identify unexpected condensation conditions

Common Design Mistakes

Industry experience has identified several recurring design and operational errors that compromise inlet separation performance:

• Undersized scrubber: Designing for average flow rather than maximum; the K factor is exceeded during peak rates, causing liquid carryover
• No mist eliminator: Relying on gravity separation alone; fine droplets pass through to the absorber
• Insufficient liquid holdup: Scrubber overwhelmed during slug events, causing liquid carryover before dump valve can respond
• Long piping runs: Excessive distance between scrubber and absorber allows re-condensation and liquid accumulation
• No low-point drains: Horizontal piping without drains collects liquid that is periodically swept into the absorber
• Missing ΔP measurement: Fouled mist eliminator goes undetected until foaming occurs
• Inadequate nozzle sizing: Oversized or undersized inlet nozzles cause poor flow distribution or excessive velocity

Design Checklist for Amine Inlet Separation

References

1. GPSA, Chapter 21 — Hydrocarbon Treating
2. API 12J — Specification for Oil and Gas Separators
3. GPA Technical Publication TP-18 — Amine Best Practices
4. Kohl, A.L. and Nielsen, R.B., Gas Purification, 5th Edition, Gulf Publishing