Jan-2019

Feed conditioning technologies for gas processing plants

Recent contactor developments remove soluble gas phase contaminants from the feed gas stream.

SCOTT NORTHROP, ExxonMobil Upstream Research
DAVID B ENGEL, Nexo Solutions, Exion Systems Division

Article Summary

Amine solvent foaming is a common problem in gas processing plants, including those ahead of liquified natural gas (LNG) manufacturing facilities. This can lead to reduced gas throughput and, in severe cases, solvent carryover and perhaps even plant shutdown. This foaming is ultimately caused by changes in the physical and chemical properties of the solvent. Chemical contaminants can lower amine solution surface tension and change the surface rheology in such a way that foaming tendency is augmented and foam is stabilised. Earlier work has shown that these contaminants are not restricted to liquid hydrocarbons, but can be from a variety of other possible sources. While some of the contaminants may originate from within the amine unit itself, many are introduced with the feed gas, such as upstream production chemicals and produced water among others. While antifoam products can temporarily alleviate foaming episodes, they can also be a detriment and build up over time, fouling vessels and activated carbon beds.

Some LNG plants employ inlet coalescers, filters or a water wash to remove contaminants in the feed gas. However, these systems may not be completely effective for the removal of certain contaminants. Furthermore, the vessels or water demands of these wash systems can be large and relatively inefficient. This article describes new technologies to prevent the introduction of contaminants into amine units. The novel systems are installed inline with the feed gas pipe and comprises a compact water wash device capable of removing water soluble components such as surfactants and salts from incoming feed gas. The spent water can be treated and recycled to minimise water make-up and clean water consumption.

Gas treating for LNG manufacture
Natural gas is treated to remove H2S and CO2 to meet pipeline or other downstream process specifications. Removal of H2S and CO2, known as acid gases, to low specifications such as those for LNG production, demands much more from processing units. For LNG production, the H2S and CO2 specifications are usually 4 ppm and 50 ppm, respectively. Very few, if any, unprocessed natural gas streams contain such low levels of those acid gas contaminants. Consequently, the vast majority of natural gas (including pipeline gas with 4 ppm H2S and 1-2% CO2) used for LNG worldwide (approximately 244 million t/y or about 22 billion cu ft/d in 2015) must be treated at least for CO2, often using liquid reagents (also called solvents) such as alkanol amines. The chemistry of amine treating for CO2 removal is well known and documented elsewhere.

While many amine units function well over the life of the LNG facility, some are prone to periodic or even frequent foaming events. This article discusses likely causes and potential solutions to these foaming episodes in amine units, which also apply to gas treating in general.

Amine solvent foaming
When gas is routed through a liquid such as an amine solvent flowing across trays of an amine unit contactor (or regenerator), a short-lived, quick-breaking froth normally develops on top of the amine solvent liquid layer. If the gas bubbles or pockets cannot break the liquid-vapour interfacial structure quickly, they become encapsulated in the liquid phase and form what is commonly referred to as foam. Foam is essentially a collection of gas bubbles encapsulated inside a liquid film that will not easily coalesce or rupture. Packed columns are less prone to foaming as upward flowing gas tends to flow across the surface of the downward flowing liquid instead of through the liquid layer on a tray. However, packed columns are not immune to liquid hold-up and other symptoms of foaming, hence the following discussion applies to them as well.

To better understand foam, one needs to consider two different aspects of it: foaming tendency and foam stability. Foaming tendency refers to the ease with which liquid film will encase gas bubbles. There is not a completely standardised measure for foaming tendency. However, a relative measure can be obtained by testing a fixed volume of amine solvent in a graduated cylinder and flowing air or nitrogen through a porous frit at a set rate (1000 ml/min), then measuring the level of foam generated.

Foam stability is related to the elasticity of the liquid layer around the gas bubble and the ability of the film to resist rupturing. Each gas bubble has an interfacial layer or ‘skin’ that confers resistance and elasticity (hindering coalescence and structural collapse), enabling the liquid film around it to flex as the gas bubble deforms, expands, or contracts. A rough measure of foam stability can be obtained using the test described previously by turning off the gas flow and determining the amount of time (in seconds) it takes for the foam to completely break. This is also expressed as foam break rate. Figure 1 shows an apparatus used to test foaming in amine solvents. The column has a bottom porous glass frit for gas dispersion. Interestingly, some amine solvents display high foam tendency, but the foam is short-lived once gas is shut off, and break rates are fast. In other cases, the foam tendency is not as high, however the foam stability is strong with slow break rates. The worst scenario is an amine unit with a solvent that has both high foam tendency and strong stability.

When an amine unit circulates a solvent that displays foaming tendency and foam stability, foam is initiated when process perturbations occur beyond what the unit can tolerate. A decrease in surface tension will sometimes correlate with an increased foaming tendency of the solvent, such as when liquid hydrocarbons are introduced into the system. However, this foam can be short-lived and, in many cases, goes unnoticed. Surfactants and other organic compounds can increase the foaming tendency as well as foam stability. When this type of foaming occurs, it does not go unnoticed and a number of process changes may be observed, such as:
• Differential pressure increase across the contactor and/or regenerator
• Decrease in contactor and/or regenerator bottoms liquid level
• Temperature bulge position changes inside the contactor tower
• Increasing liquid level in the amine contactor after-scrubber, as amine solvent is carried over with the treated gas (leading also to amine solvent losses)
• Increase in H2S in the treated gas (and CO2 for LNG cases)
• Amine contamination of the regenerator reflux water.

Note that mechanical damage to internals, solids fouling of internals or excessive gas velocity inside the amine unit contactor (or regenerator) can result in tower flooding and mechanical frothing/foaming which is distinct from pure chemical foaming. However, the symptoms are similar to those described above, so it can be difficult to distinguish foaming from flooding based on operational observations alone.

In a severe flooding-frothing-foaming event, the first action (after dosing antifoam into the system) is usually reducing the gas rate to lower the differential pressure across the contactor and allow any held-up liquid to fall into the bottom of the contactor tower. It can take a substantial reduction in gas rate to recover control of the system. In addition to the reduction of feed gas to the amine unit, the upset must work itself through the rest of the unit and may require further operator intervention such as flash tank and regenerator adjustments. If frequent, these foaming events can measurably reduce the output of the LNG production facility.

Foaming of the amine solvent can often lead to carryover from the contactor or regenerator caused by entrained liquids with the treated gas or acid gas, respectively. Most amine units have separation vessels such as a knockout drum at the contactor outlet to recover most of the amine solvent carryover. If the amine unit is treating liquid hydrocarbon (for instance, condensate co-produced with gas), ‘foam’ can be replaced by ‘emulsion’ in the above discussion.

Any carryover from the amine contactor in the treated hydrocarbon  by emulsification is recovered using a liquid coalescer and/or a water wash stage. These devices will remove any  emulsified amine solvent present in the treated liquid hydrocarbon. An alternative strategy is to inject 1-100 ppm of an emulsiion breaker into the hydrocarbon feed upstream of the amine conatctor.t carryover may reach downstream units such as dehydration plants, mercaptan removal plants or caustic treaters. Sometimes the amine solvent carryover can infiltrate the main fuel gas system. Foaming in a regenerator is also detrimental as contaminated amine solvents often do not regenerate fully. Furthermore, carryover with the acid gas can reach the sulphur recovery unit, flare system or other downstream process.

Antifoam addition is a common method to temporarily control the deleterious effects of foaming. However, the effectiveness of a given antifoam may be limited as amine units sometimes use antifoam and experience little to no apparent foam reduction. Some plants use antifoams in the amine unit on a regular basis for short-term relief, but this can harm the solvent in the long term.1 In fact, antifoams should not be used on a constant or daily basis. Root cause analysis of foaming and the elimination of its source is the best way to deal with a foaming amine solvent. Nevertheless, antifoams may need to be used when sporadic foaming incidents occur and the source of foaming agent has not yet been identified.

Antifoams in amine units can accumulate on top of the solvent as a separate phase in the amine contactor flash tank or the regenerator sump for example. Antifoams also can render activated carbon beds useless as they saturate the carbon and hinder entry of contaminants into the pore structure. Silicone antifoams are actually small particles (1-10 microns in size) that are very effective for reducing foam (10 times more effective than normal polyglycol antifoams). However, silicone-based antifoams should not be used in amine units because of their inherent physical incompatibility with aqueous solvents. Most silicone based antifoams are removed using filters 10µ or smaller.

Amine solvent foaming can usually be limited to a single root cause: chemical contamination. However, chemical contamination can originate from a number of sources. Clean amine solutions will not foam and should not froth. Hence, standard design and operation advice for amine units typically includes: i) specifying efficient inlet solids and liquids separation systems to prevent ingress of most feed contaminants; ii) setting the lean amine temperature at least 10°F above the inlet gas temperature to avoid liquid hydrocarbon condensation in the contactor; and iii) including 15-25% slipstream of carbon adsorption to adsorb soluble contaminants in the solvent. Additional measures include the  sparing use of effective antifoams  (applied efficiently), lean and rich filtration to remove suspended

solids and andjusitng the amine solvent concentation. A common practice used during foaming in an amine unit is to discard the returned condensted water at the regenrator overhead condenser. These can accumulate foaming agents.