Hydrocarbon Processing - December 2022 - 46

Process Optimization
DMDS was (generally) not present in
the gas inlet to the treaters. Two instances
were found in addition to the situation
mentioned above. In the first MDEA
fuel gas absorber, operating at 6 barg, the
DMDS concentration decreased from 18
ppmv to 8 ppmv across the treater. Secondly,
in a DEA absorber operating at 6
barg, the inlet DMDS concentration decreased
from 14 ppmv to 11 ppmv.
Simulated vs. actual removal with
DEA. Three commercially available simulators
were considered for their ability to
predict organic sulfur removal from a fuel
gas by generic DEA solvent. Simulators 1
and 2 had R1
SH, R2
SH, R3
SH and C2
SH, R4
SH, COS
and DMS as available components, while
Simulator 3 only had the capability to
predict C1
SH removal and was
therefore not included in this assessment.
The measured removal of the mercaptan
species from a recent field test (not
Preemraff Lysekil) was compared to the
two model predictions (FIG. 10). From
this and other industry experiences, it
appears that current (2020) commercial
simulators significantly underpredict the
removal of organic sulfur species in generic
amine systems.
Onsite optimization at Preemraff
Lysekil. As part of the emissions minimization
strategy at Preemraff Lysekil,
an analytical test was conducted across
the facility's treating system to identify
sources of sulfur emissions. Onsite testing
eliminated the TGTU, as it was working
exceptionally well and no tail gas from
the Claus plant was leaking into the stack.
Further analysis of the main amine system
traced the source of the emissions to organic
sulfur species in the fuel gas. These
species were mainly entering the system
via a DEA fuel gas absorber, which was
also treating vaporized LPG from a thermal
cracking unit (visbreaker). During
the testing, some variations were detected
in the inlet composition and the feed gas
flowrate. The bulk of the sulfur leaving this
column with the treated fuel gas was in the
form of methyl and ethyl mercaptan.
Follow-up test runs were arranged to
determine if the organic sulfur species in
the fuel gas and, therefore, the SO2
emisFIG.
8. Ethyl mercaptan removal in DGA vs. absorber V/L ratio for 5 absorbers.
sions from the plant, could be reduced
by operational changes. Adjustments to
column temperature and pressure did
not show appreciable results: ranges were
limited by hardware considerations. Adjustment
of the upstream cut-points on
the visbreaker unit did, however, have a
significant impact and sent more mercaptans
and DMS to the light naphtha fraction
rather than to the fuel gas absorber.
The light naphtha fraction is subsequently
hydrotreated, effectively converting the
mercaptans and DMS to H2
S, which can
easily be absorbed in an amine treater.
The absorber was initially operating at
low flood levels and, as such, did not have a
high degree of contact between the amine
solvent and the gas. The low contact was
sufficient for the removal of H2
S and COS,
FIG. 9. Ethyl mercaptan removal in DEA and MDEA vs. solvent strength.
TABLE 2. Field measured removal percentage of C3
in various amines
C3
MEA
DEA
MDEA
SH
(# data points)
39 (1)
30-79 (4)
13-29 (3)
C4
SH
(# data points)
45 (1)
34-83 (3)
50 (1)
46 DECEMBER 2022 | HydrocarbonProcessing.com
SH, C4
SH, C5
C5
SH
(# data points)
-
26 (1)
44 (1)
SH and DMS
DMS
(# data points)
35-67 (2)
22-68 (5)
70-88 (2)
but the removal of the mercaptans was not
optimal. Once the amine circulation was
increased, the methyl mercaptan removal
by the DEA solution increased from 24%
to 78% (see FIG. 6). For ethyl mercaptan,
there was a step-change increase from
15% removal to 40%-60% removal as
the amine flow rate was increased to the
point where there was adequate contact
(FIG. 11). From that point, at subsequent
smaller gas-to-amine ratios, there is no obvious
correlation to the removal of R2
By adjusting gas-to-amine solvent
SH.
ratios, it was possible to increase the removal
of the organic sulfur species from
21% to 71% of the inlet concentration.
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