Hydrocarbon Processing - December 2022 - 43

Process Optimization
is significantly faster in primary (MEA,
DGA) amines than in secondary and tertiary
ones. In DGA, the degradation product
[N, N bis(hydroxyethoxyethyl) thiourea
abbreviated as BHEEU] is reversible
in a reclaimer; therefore, COS degradation
is primarily a concern in MEA systems
where it converts MEA to diethanolurea,
which is not reversible.
According to Dawodu,13
COS reacts
with DEA to form MEA, bis-hydroxyethyl
imidazolidone (HEI), bis hydroxyethyl
piperazine (BHEP), hydroxyethyl
oxazolidone (HEOD), tris-hydroxyethyl
ethylenediamine (THEED) and bis-hydroxyethyl
ethylenediamine (BHEED).
Butwell, et al.3
reported that only 2% of
COS in the feed gas reacted with DEA irreversibly,
while removal of up to 80% is
possible primarily through the hydrolysis
reaction. DIPA is thought to degrade with
COS, but the rate of reaction is slower than
the time allowed for experiments to determine
this.2
DIPA is considered a suitable
solvent for COS removal in conjunction
with a physical solvent (i.e., the sulfinol-D
formulation). Rahman, et al.12
did not detect
any reaction of COS with MDEA or
dimethylethanolamine (DMEA).
While it is thought possible for COS to
react directly with water, this reaction is too
slow to be industrially relevant. Cantrell, et
al.14
applied Danckwerts' criteria15
to show
that the reaction of COS directly with water
is not relevant in terms of available contact
time on amine absorber trays.
Both COS and mercaptan sulfur removal
are disadvantaged by the presence of H2
and CO2
S
in the amine. Therefore, most of
their removal is thought to be in the top
part of an amine absorber after the bulk
of the H2
S and CO2
have already been absorbed.
Following from this theory, some
industry rules-of-thumb have evolved:
1. The removal of organic sulfur
only happens after most of the
H2
S and CO2
have been removed.
Anecdotally, columns with more
contact stages have reported better
removal. An example can be found
in literature.11
2. Mercaptan and COS removal are
favored by lower lean amine CO2
and H2
S loadings. Therefore,
more regeneration (reboiler duty
use) will be required.
3. Lighter mercaptans exhibit larger
solubilities than heavier mercaptans
in amine solutions. Heavier
FIG. 2. Vapor pressures of possible feed components at 21°C.
mercaptans are increasingly nonpolar
(more hydrocarbon-like)
with an increasing carbon number,
therefore less soluble in the highlypolar
aqueous amine.
4. Amine systems attempting to slip
CO2
(tail gas treating and acid gas
enrichment units) will not have
good organic sulfur removal, as
significant absorption of CO2
will be occurring in the top trays of
the contactor, which will compete
with organic sulfur removal.
Mercaptan has been shown to react
with molecular oxygen in basic aqueous
solutions under mild temperature and
pressure conditions to form disulfides
and peroxide or water.16
Uncatalyzed
conversion rates are slow, but a wide
range of simple metal salts can serve this
purpose, including Fe2
CuSO4, among others.17
(SO4
)3
, CoCl2
and
This reactivity
is the basis for the Merox processes developed
by UOP used to sweeten a wide
variety of hydrocarbon products, from
LPG to jet fuel. While Merox units use
advanced proprietary catalysts for efficient
conversion, the simple metal salts
commonly encountered in amine-based
treating units from the process of corrosion
may act in a similar manner, if the
unit suffers from oxygen incursion.
Experimental work by Borgeson18
almost
a century ago suggested that mercaptans
could be formed from the reaction
of H2
S with some aldehydes, ketones,
olefins, acetic and propionic acid. None of
these experiments was done in an alkaline
environment and mercaptan was detected
only by odor due to the analytical limitations
of the time.
Concurring with these observations,
preliminary lab experiments by the authors'
company led to the detection of
mercaptan in the gas headspace above
aqueous amine solutions mixed with
methanol or acetone after pressurizing
with H2
S gas and heating to temperatures
approximating those encountered in an
absorber tower. While further investigation
of these results is required, they
suggest it may be reasonable to observe a
change in the ratios or even an increase in
concentration of organic sulfurs between
the outlet and inlet of an absorber under
certain conditions.
The theory of organic sulfur phase
partitioning. One difficulty in deciding
which amine is best suited to remove
particular organic sulfur species is the
question of exactly how it will partition in
the various liquid and vapor streams in a
refinery or gas plant. One method of determining
sulfur species partitioning is via
vapor pressure comparisons to associated
hydrocarbon streams. FIG. 2 shows a logscale
bar graph of vapor pressure, in descending
order, for components that may
be present in a feed hydrocarbon stream.
As indicated by Likins and Hix,19
when
considering vapor pressures only, the
chart shows that COS should distribute
into the propane stream and possibly into
an ethane/propane mix stream. Methyl
mercaptan (R1
SH) should distribute primarily
into the n-butane stream with some
going with both the i-butane and gasoline
streams. Ethyl mercaptan (R2
and CS2
SH), DMS
should end up primarily in the
gasoline stream with only minor distribution
into the n-butane stream. The other
Hydrocarbon Processing | DECEMBER 2022 43
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