Page 163 - Gas Purification 5E

AlkanoIamines for Hydrogen Surfide and Carbon Dioxide Removal 151

3. Decreased temperature (Compare tests 4 and 5).
4. Decreased number of trays (Compare tests 6 and 7).

Only 8 of 18 tests are included in the table. In all but one of the 18 tests (with minimum
solution flow rate and 10 trays) the H2S content of the product gas was less than 1 ppm.
However? even in this one test, increasing the steam rate to the reboiler from 1.2 to
1.44-1.56 lb steam per gallon of solution at the same absorber conditions resulted in a return
to less than 1 ppm H2S product gas. Production of a product gas containing less than 1 ppm
H2S was maintained at solution feed temperatures as high as 145"F, although C02 slippage
declined as the solution temperature increased (Ammons and Sitton, 1981).
Detailed operating data on a plant using an aqueous mixture of MDEA and DEA are given
by Harbison and Handwerk (1987). The use of an amine mixture was not intentional in this
case, but apparently resulted from carryover from a DEA plant or the inadvertent use of
DEA as makeup to the MDEA unit. Operating data taken on the system during a 24 hour test
run are summarized in Table 2-28. During the test period the solution contained 21.88
MDEA and 4.2% DEA. The results of the test showed the plant to be capable of producing
gas containing only about 0.002 vol% H?S (i.e., 99% removal) while removing only about
32% of the C02. Vickery et al. (1988) used the Harbison and Handwerk plant data to verify
the performance of the GASPLANT-PLUS flow sheet simulator with the AMCOLR rate
model for amine columns. The model duplicates actual plant performance reasonably well,
and predicts that pure (25%j MDEA will provide greater selectivity (more CO2 in the prod-
uct gas) and purer product gas, with regard to HIS, than a mixed amine of the type actually
used in the plant.

Diisopmpanolamine Plants

Operating data for three ADP process plants, which employ aqueous DIPA solutions, are
provided in Table 2-29. These plants operate at pressures from 59 to 360 psig on gases from
high-temperature oil processing units which usually contain COS and CS2. Data on COS
removal are given for Plant 1, and indicate that the ADP process removes 50% of the COS
present in the feed gas. With regard to H2S removal, the product gas purity varies from 2
ppm for Plant 1, which treats 350 psig gas with an H2S:C02 ratio of 1:11, to 100 ppm for
Plant 3, which treats a gas containing 15.6% H2S and no C02 at a pressure of only 59 psig
(Klein, 1970:).

Organic Sulfur Removal by Amine Solutions

This section covers the removal of COS, CS?, and light mercaptans from gas streams by
amine solutions. These are the principal organic sulfur compounds normally encountered in
fuel and synthesis gases. The removal of organic sulfur compounds from liquid hydrocar-
bons is discussed in the next section. The presence of the above components (and many other
reactive species) in a gas to be treated raises two questions: (1) How much, if any, of the
material will be removed during the treating operation? and (2) will the impurities cause
deterioration of the amine solution'? The question of solution deterioration by reaction with
various gas impurities is discussed in detail in Chapter 3; this discussion is concerned pri-
marily with removal of carbonyl sulfide, carbon disulfide, and mercaptans from the gas by
amine solutions.