Page 61 - Gas Purification 5E

Alkanolamines for Hjidrogen Sulfide and Carbon Dioxide Removal 51

H2S and CO,. As discussed in Chapter 3, secondary amines are much less reactive with COS
and CS2 than primary amines, and the reaction products are not particularly corrosive. Conse-
quently, diethanolamine and other secondary amines are the better choice for treating gas
streams containing COS and CS:. The low vapor pressure of diethanolamine makes it suitable
for low-pressure operations as vaporization losses are quite negligible. One disadvantage of
diethanolamine solutions is that the reclaiming of contaminated solutions may require vacuum
distillation. Another disadvantage of DEA is that DEA undergoes numerous irreversible reac-
tions with COz, forming corrosive degradation products, and for that -on, DEA may not be
the optimum choice for treating gascs with a high C02 content (see Chapter 3).
Application of diethanolamine solutions to the treatment of natural gas was first disclosed by
Bertheir (1959) and later described in more detail by Wendt and Dailey (1967), Bailleul
(1969), and Daily (1970). This process, which is commonly known as the S.N.P.A.-DE.4
process, was developed by Societe Nationale des Petroles d'Aquitaine (S.N.P.A.)' of France in
the gas field at Lacq in southern France. S.N.P.A. reco-qized that relatively concentrated aque-
ous diethanolamine solutions (25 to 30% by weight) can absorb acid gases up to stoichiomemc
molar ratios as high as 0.70 to 1 .O mole of acid gas per mole of DEA, provided that the partial
pressure of the acid gases in the feed gas to the plant is sufficiently high. If the regenerated
solution is well enough stripped when returned to the absorber and the operating pressure is
high, purified gas satisfying pipeline specifications can be produced. The presence of impuri-
ties such as COS and CS2 is not injurious to the solution. Under nod operating conditions,
DEA decomposition products are removed quite easily by filtration through activated carbon.
In general, diethanolamine solutions are less corrosive than monoethanolamine solutions unless
corrosive decomposition products from side reactions build up in the solution [see Chapter 3).
As a result of S.N.P.A.'s experience in Lacq, the S.N.P.A.-DFiA process has been widely
used for the treatment of high-pressure natural gases with high concentrations of acidic com-
ponents, especially if COS and CS2 are also present in appreciable amounts. Beddome
(1969) reported that in 1969 the S.N.P.A.-DEA process predominated for the recovery of
sulfur from natural gas in Alberta, Canada. Comparative operating data for mono- and
diethanolamine systems, as reported by Beddome (1969): for typical Canadian gas-treating
plants are shown in Table 2-2. Although not stated in the article, it is assumed that all plants
were operating at a pressure of about 1.000 psig, which is typical for Canadian operation.
Diglycolamine

The use of aqueous solution of Diglycolamine, 2-(2-aminoethoxy) ethanol, was commer-
cialized jointly by the Fluor Corporation (now Fluor Daniel), the El Paso Natural Gas Com-
pany, and the Jefferson Chemical Company Inc. (now the Huntsman Corporation) (Holder,
1966; Dingman and Moore, 1968). The process employing this solvent has been named the
Fluor Econamine. process. The solvent is in many respects similar to monoethanolamine,
except that its low vapor pressure permits its use in relatively high concentrations, typically
40 to 609, resulting in appreciably lower circulation rates and steam consumption when
compared to typical monoethanolamine solutions. A comparison of operating data for gly-
col-monoethanolamine and Diglycolamine solutions in a commercial installation, which
treats natural gas containing 2 to 5% total acid gas at a pressure of 850 psig is shown in
Table 2-3, Holder (1966).

'Now Societe Nationale Elf Aquitaine (Production) (SNEAP).