Hydrocarbon Processing - October 2022 - 22

Plant Safety and Environment
Amine degradation products can be
of particular concern when using commodities
like primary and secondary
amines, such as MEA and diethanolamine
(DEA). Examples of associated,
problematic degradants include bicine
and tris-hydroxyethyl ethylenediamine
(THEED), which can result in corrosion
of process equipment when not properly
managed. Formulated, proprietary aminesc
substantially
mitigate these risks.
These species could ultimately build
up to a concentration that is undesired and
should, therefore, be removed from the
process.12
However, in this study, the formation
and accumulation of both HSAS
and amine degradation products were not
found to be a cause for operational problems,
so the replacement of the amine solvent
inventory was not necessary (FIG. 7).
This data clearly illustrated the very low
reactivity of the proprietary solventa
toward
the formation of degradation products
vs. generic gas treating solvents.
The primary HSAS encountered in this
study was formate (> 80% of the HSAS).
The rest of the anions were primarily thiocyanate
and acetate. Formate is formed in
this system in several different reactions,
such as HCN hydrolysis.
For downstream utilization of the CO2
lean gas, the quality of such gas is critical.
Therefore, the CO2
gas was monitored, along with the H2
COS and NH3
content in the treated
S,
contents. These components
are typically present at concentrations
of 1 ppmw-30 ppmw in the feed
gas. Amine solvents are also selective toward
sulfur species, and it was observed
that a high sulfur removal efficiency
could be achieved. The CO2
a measured H2
lean gas had
S concentration between
1 ppm and 2 ppm, and this has the potential
to be removed until even lower values
under more optimized conditions for H2
S
capture. Although this is not zero, and it
is still an issue for the use of the CO-rich
gas to conduct syngas chemistry, the bulk
removal of H2
S and COS would allow for
an affordable deep removal of such species
in a guard-bed setup prior to entering the
downstream CO conversion unit.6
The downside of the H2
the amine solvent was that it is released
with the CO2
. Consequently, the H2
concentrated in the CO2
with roughly a factor 4 vs. the input concentration.
In essence, this means that the
CO2
outlet stream
from treated BFG contains 50 ppm-
22 OCTOBER 2022 | HydrocarbonProcessing.com
S capture by
S is
60 ppm of H2
S, and, when treating COG,
this could be as much as 250 ppmw of
H2
S. Further purification of the captured
CO2 would need to be considered in
case this CO2
is to be processed further
via either carbon capture and storage or
carbon capture and utilization. In this
respect, it is also important to note that
traces of amine could be present in the
captured CO2
. The CO2
.
from the reboiler
was analyzed and was found to contain
1 ppm-2 ppm of the amine, but no NH3
was detected in the CO2
Summary and outlook. A CO/CO2
separation pilot line was developed and
operated with co-funding from the Interreg
2 Seas program. The unit was installed
in the heart of the ArcelorMittal steel mill
in Ghent, Belgium. This enabled the unit
to be fed with real industrial waste gases
(e.g., BFG and COG) directly from the
major gas lines in the facility.
In the 2019-2021 timeframe, the
unit was mainly operated on BFG. It was
shown that the inlet filters were effective
in removing (acid) condensate and dust
from the feed gas. Operation on COG
demonstrated that the current filter design
did effectively remove the tars present
in this gas. Consequently, severe process
upsets were observed in the run with
COG, mostly due to foaming and fouling
caused by the presence of aromatic tars in
the amine solvent. Additional measures to
clean COG are needed to utilize this gas.
Several thousand hours of operation
with BFG demonstrated that the applied
proprietary solventa
S and COS in
can capture CO2 from
BFG at greater than 90% efficiency with
minimal degradation. More than 95% efficiency
was achieved under optimized
conditions. In addition, H2
the gas were also captured, resulting in a
treated gas with H2
S and COS in a low
lean gas for CO
ppm range (i.e., 1 ppm-5 ppm). This enabled
the use of the CO2
conversion chemistry, which is typically
less tolerable for impurities and requires
sub-ppm levels. Although deep removal
for chemical conversion is still required,
the bulk of the sulfur impurities can be effectively
removed using an amine system.
A trial with LanzaTech fermentation technology
for ethanol production from BFG
was conducted successfully. In a follow-up
project, for which the CO/CO2
separation
pilot line will serve as a feedstock
pretreatment, the project partners will explore
the subsequent polishing and catalytic
conversion of the CO-rich gas.
It was also demonstrated that the relatively
poor quality (dust, impurities) of
the BFG had limited effect on the longterm
quality of the proprietary solventa
.
Consequently, it was anticipated that an
excessive make-up of the amine solvent
would not be required, which had a positive
impact on the operational costs. As
expected, while still not critical for the
process, the much poorer quality of the
COG showed a higher degradation rate
for the solvent. In combination with the
observed fouling of the unit when running
on this gas, it was decided that amine wash
was not a good solution for treatment of
COG and/or BFG + COG mixtures without
any upstream pretreatment for tar and
oil removal to values of less than 100 ppm.
Operations with BFG also confirmed
that amine carryover to the CO2
was low
and that the energy for solvent regeneration
was in line with expectations and on
par with typical numbers for this technology
(i.e., 2.3 GJ/mT-4.2 GJ/mT CO2
captured). This energy use could be significantly
improved when heat integration
with the exothermic CO conversion process
was implemented.13
The quality of the captured CO2
remains
a challenge. As the amine solvent
also captured the sulfur species, these will
concentrate in the CO2
. Consequently,
for
H2S levels of 50 ppm-250 ppm were observed.
To be able to send this CO2
storage and/or utilization, desulfurization
of the CO2
must be considered. A suitable
technology for this could be Villadsen's
electrochemical desulfurization.14
ACKNOWLEDGMENTS
This project was performed by the Carbon2Value
consortium and co-funded by the EU's Interreg 2
Seas program (Project 2S01-94). The authors kindly
acknowledge numerous internal and external
contributors to the project, and our external partners
at
ArcelorMittal Ghent, Petrogas BV, Dow
Industrial Solutions, Dow Chemical Lab, Dow
Hydrocarbons R&D, LanzaTech, Provinciale
Ontwikkelingsmaatschappij Oost-Vlaanderen
(POMOV), the University of Lille in France, the
Institute for Sustainable Process Technology (ISPT),
and Impuls Zeeland (Smart Delta Resources program).
NOTES
a
b
c
Dow Industrial Solutions' UCARSOL™ AP 814
solvent
Dow Industrial Solutions' UCARSOL™ GT-10
antifoam
Dow Industrial Solutions' UCARSOL™ amines
LITERATURE CITED
Complete literature cited available online at
www.HydrocarbonProcessing.com.
http://www.HydrocarbonProcessing.com http://www.HydrocarbonProcessing.com
Hydrocarbon Processing - October 2022

Table of Contents for the Digital Edition of Hydrocarbon Processing - October 2022
