Mar-2018

Surfactant-stabilised emulsions in amine units for LPG treating

Emulsion formation by surfactants is one of the most complex problems facing amine units treating refinery LPG.

DAVID ENGEL, HEATH BURNS and SCOTT WILLIAMS
Nexo Solutions

Article Summary

Contamination in refinery liquefied petroleum gas (LPG) feed streams to amine units is one of the leading causes of process upsets and diminished throughputs. More detailed testing shows that, specifically, surfactants in the LPG are one of the most damaging contaminants affecting the process. Surfactants often pose a number of challenges such as LPG-amine solvent emulsification, amine solvent losses and downstream caustic unit contamination. In fact, surfactants in the feed LPG is perhaps one of the causes of low treating performance, often leading to copper strip failure. Surface active contaminants in LPG streams should therefore be sampled, analysed, and removed in order to enable processing plants to run smoothly. This article discusses how the stream LPG is sampled, revealing the presence of surfactants directly linked to emulsion formation and the associated amine solvent losses. Specialised methods for the presence of surfactants, such as surface tension and surface rheology evaluation, are examined, as well as techniques for on-site sampling of LPG. The article additionally discusses measures to be implemented to remove surfactants and eliminate their downstream effects.

Surfactant contaminants
Surfactants in the liquid LPG hydrocarbon phase feeding amine units can cause a number of detrimental effects, most predominantly LPG-amine solvent emulsification. Surfactants can also be present in the water phase if the LPG contains emulsified or free water. Emulsion formation inside the amine unit contactor (treater) can then lead to several secondary problems such as the inability to meet H2S removal specifications and amine solvent carry- over to downstream units. One of the most common and difficult challenges in processing units such as amine units is dealing with the various forms of surfactant ingression into the system.

Surfactants are interfacially active molecules. They generally consist of a polar section (head) or group and a non-polar group, generally hydrocarbon chains (see Figure 1). The polar part of the molecule can interact with polar solvents like water and is therefore also called the hydrophilic portion. The non-polar part, on the other hand, can interact with non-polar materials such as hydrocarbons and is therefore called the lipophilic or hydrophobic portion.
Surfactants can be classified according to the charge of their polar head group:
•    Anionic surfactants have a negatively charged head group
•    Cationic surfactants have a positively charged head group
•    Zwitterionic surfactants have a zwitterionic head group (positive and negative charge)
•    Non-ionic surfactants have an uncharged polar head group.

Surfactants migrate preferentially to interfaces where they find the lowest and most energetically favourable conditions because of their two-component structure. At the water phase surface, for example, the surfactants orient themselves in such a way that the head group contacts the water and the hydrocarbon chain points to the hydrocarbon phase (see Figure 2). Thus, surfactants ‘reside’ in-between two phases as they can form strong interactions with both phases. The interfacial tension consequently decreases. The addition of surfactants often facilitates the mixing of non-polar and polar phases, which is used in many industries that use emulsions.

The decrease of the interfacial tension caused by surfactants becomes stronger as more surfactants are located at the hydrocarbon/water interface. Once the interface and hydrocarbon/water phases are saturated, the addition of more surfactants will not change the interfacial tension any further.

It is important to mention that solids such as iron sulphides can, under certain conditions, also act as a surfactant because the solids’ surface can interact with both water and hydrocarbon phases at the same time. For the purposes of this article, 
solid based surfactants (particles) will not be covered; only molecular surfactants as described previously are discussed.

Examples of some surfactants commonly found in hydrocarbon processing feed streams, such as amine units, include lubrication oils, produced water and upstream process additives. Lubrication oils from gas compressors typically contain  a high percent base oil (most often petroleum fractions, called mineral oils) and about 10% additives for various functions, which often have surface active properties. Additives that deliver reduced friction and wear, increased viscosity, improved viscosity index, as well as resistance to corrosion, oxidation, ageing, and contamination in upstream processes also often have surface active properties. Upstream process additives, on the other hand, can be biocides, corrosion inhibitors, H2S scavengers, or paraffin inhibitors to name a few. Corrosion inhibitors (filming amines or quaternary ammonium salts with alkanol segments) are an example of process additives with surfactant properties. Figure 3 shows how a corrosion inhibitor filming amine performs, and a possible general molecular structure. As with surfactants in general, a filming amine has a hydrophobic section (long alkyl chain called tail) and a hydrophilic section (polar ionic centre called head).

To illustrate this point, Figure 4 shows the change in surface tension of distilled water compared to distilled water when used as a scrubbing agent for surfactants. The decrease in surface tension from 
72 mN/m (millinewtons/metre) to 46 mN/m is a clear indication of surfactant presence. Similar effects are observed with some upstream process additives such as corrosion inhibitors. The decrease in surface tension leads to mechanically induced contamination (emulsions or foaming), and dissolved contaminants downstream as separation equipment loses its separation efficiency. Poor phase separation leads to multiple downstream impacts in addition to secondary effects such as solvent losses.

LPG and amine solvent emulsion formation
When a liquid hydrocarbon travels across the amine solvent inside the amine unit contactor (treater) and liquid pockets or droplets cannot break the interfacial structure, they become encapsulated in the amine solvent aqueous liquid phase and form what is commonly referred to as emulsion. Emulsion is essentially a liquid droplet that will not merge (coalesce) with other liquid droplets because of the surrounding interface film. When a liquid treating amine unit has a solvent that experiences emulsification in the contactor (treater), it is initiated when certain contaminants are present or process perturbations occur beyond what the unit can tolerate. A decrease in surface tension will increase emulsification tendency, such as when some hydrocarbons are present. However, the emulsions are short lived and in most cases they are unnoticed. Surfactants, on the other hand, can greatly increase emulsion stability and emulsion tendency. When emulsification occurs, a number of operational changes may be observed.

Emulsification of the amine solvent can often lead to carry-over from the contactor with the treated hydrocarbon. Most amine units will have a separation vessel such as a knockout or separator drum at the contactor outlet to separate most amine solvent carry-over. Any carry-over from the amine contactor into the separator drum is often followed by a water wash stage to remove any emulsified amine solvent present in the treated liquid hydrocarbon. Amine solvent 
carry-over can also reach a number of downstream units such as dehydration plants, mercaptans removal plants or caustic treaters. In some cases, emulsification in the contactor is followed by foaming in a regenerator. This is also detrimental as rich amine sol­vents do not regenerate properly. In addition, carry-over with the acid gas can reach the sulphur recovery unit (SRU), flare systems or any other downstream process.