Page 241 - Gas Purification 5E

Mechanical Design and Operation of Alkanolarnine Plants 227

Control of External Contamination

Foaming problems can usually be minimized by limiting the access of external contami-
nants such as compressor lubricating oil, well treating compounds, and pipeline corrosion
inhibitors to the alkanolamine solution. A combination of a slug catcher, inlet filterhepara-
tor, and a gas-liquid coalescer installed in series in the feed gas line is the best way to pre-
vent external contaminants from entering the system with the feed gas and can substantially
reduce amine filtration costs and improve plant performance. According to Pauley and Perl-
mutter (1988), conventional inlet separators have difficulty in removing aerosols 3 microns
or less in diameter, while specialized, high-efficiency gasAiquid coalescers can remove com-
pressor lubricating oil droplets as small as 0.001 micron (Pauley, 1991). It is claimed that
removal of these small aerosol particles can, in some cases, substantially reduce foaming
problems in amine plants.

Prevention of Hydrocaaon Condensation and Liquid Hydrocarbon Accumulation

If the feed gas is near its hydrocarbon dewpoint, hydrocarbon condensation inside the con-
tactor and related foaming can be avoided by keeping the temperature of the lean amine
solution about 10 to 15°F above that of the gas in the amine contactor. This is usually
accomplished by using a temperature difference controller to control a bypass around the
lean amine cooler.
Amine contactors and regenerators should be supplied with differential pressure indication
and alarm to provide an early waming of foaming problems. When the differential pressure
(in feet of water) is 40 to 50% of the height between the instrument taps, the tower is usually
foaming and amine is being carried over into downstream units (Lieberman, 1980).
Heavy hydrocarbons in the feed gas to the absorber can be dissolved or entrained in the
rich amine. In systems with absorber pressures above about 100 psig, it is generally appro-
priate to use a rich amine flash drum to flash off hydrocarbon gases entrained or dissolved in
the rich amine solution. See Figure 3-1. Rich amine flash drums are usually equipped with a
skimming device to remove any liquid hydrocarbons that accumulate. Ball and Veldman
(1991) recommend that the rich amine flash drum be designed for at least 20 to 30 minutes
of liquid retention when half full. For refinery applications, where the risk of hydrocarbon
contamination is high, they recommend that the flash drum operate at as low a pressure as
possible, i.e., 5 to 10 psig, which would require pumps to transfer the rich amine to the
regenerator. Manning and Thompson (1991) recommend 10- to 15-minute residence times
for two-phase separators (gadamine solution) and 20 to 30 minutes for three-phase flash
tanks (gas/oil/amine solution). Bacon (1987) recommends liquid residence times ranging
from 5 to 30 minutes depending on the type and degree of mixing between the hydrocarbon
and amine. Long residence times and low pressure operation are probably appropriate when
treating gas streams containing heavy hydrocarbons, i.e., many refinery applications. Shorter
flash drum residence times and higher flash drum operating pressures can be considered
when the gas being treated is relatively lean as in many plants treating natural gas.

Removal of Foam-Causing Impurities hm Solution

Three techniques are commonly employed to remove impurities from gas treating plant
amine solutions: Mechanical filtration, activated carbon adsorption, and thermal reclaiming