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6. Failure of an amine solution foaming test. Bacon (1987) recommends that the foam height
and break time as measured by the standard Dow foam test be less than 200 ml and 5 sec-
onds, respectively. Smith (1979A, B) describes laboratory and field foaming tests
7. High operating costs (power, steam, and filtration costs)
8. Instrument taps plugged with particulates, solids accumulation in the regenerator overhead
condenser, and reduction in amine filter cycle length (Lieberman, 1980)

Prevention of Foaming
Summary of Foam Prevention Techniques

Foaming can be reduced or controlled by proper care of the amine solution. The following
techniques reduce amine solution contamination and minimize foaming:

1. A properly designed feed gas inlet separator and fiiter should be provided. A feed gas
coalescer should be considered for feed gas streams contaminated with compressor lubri-
cating oil and other finely dispersed aerosols (Ball and Veldman, 1991; Pauley, 1991). A
properly sized slug catcher should be provided if slugs can accumulate in the feed gas
line.
2. A feed gas water wash should be considered when the feed gas stream is severely conta-
minated with carboxylic acids or water-soluble, surface-active contaminants (Bacon,
1987). A feed gas water wash can also remove aerosols and ultra-fine particles (Ball and
Veldman, 1991).
3. Mechanical and activated carbon filtration of the amine solution. A 10 micron mechani-
cal filter on a 10 to 20% amine solution slipstream is usually sufficient; however, it is
good practice to use the smallest micron rating that has an acceptable run time between
filter element changes. Usually mechanical and activated carbon filtration of a 10 to 20%
slipstream is sufficient. However, full stream filtration may be required for Claus plant
tail gas units and for MDEA and DEA units treating feed gas streams with low H2S/C02
ratios.
4. Onsite or offsite amine solution reclaiming to remove heat-stable salts and amine degra-
dation products. No more than 10% of the amine should be tied up as heat-stable salts
(Bacon, 1987).
5. Caustic addition to neutralize heat-stable salts to mitigate corrosion and thereby reduce
iron sulfide formation (Bacon, 1987).
6. Temperature difference control of the lean amine solution feed to the absorber to ensure
that the lean amine is 10 to 15°F warmer than the feed gas.
7. A properly sized rich amine flash drum to remove entrained and dissolved hydrocarbons.
8. Liquid hydrocarbon skimming facilities in the absorber sump, the rich amine flash drum,
the regenerator sump, and the amine regenerator overhead accumulator (Bacon, 1987).
9. New plants and old plants that have undergone a major turnaround are often contaminat-
ed with oils, greases, welding fluxes, and corrosion inhibitors. A hot caustic wash (2 to 5
wt% caustic soda) followed by a hot condensate wash can remove these impurities and
help prevent foaming.
10. The minimum contact temperature in the absorber should be greater than 50 to 60°F to
ensure that high amine solution viscosity does not initiate foaming (Ballad, 1966).
11. Either batch or continuous antifoam addition (as a last resort).
A detailed review of foam prevention techniques follows.