Hydrocarbon Processing - October 2022 - 21

Plant Safety and Environment
analysis of gas treating amines, they are
reported as the weight percent of solution
that is amine bound as non-regenerable
salt. Naphthalene and tar can condense in
the solvent to create fouling material and
promote foaming, especially at cold spots.
They can also act as a binder if other inorganic
particles are present in the system
and, thus, aggravate these problems. The
acidic species can lead to higher levels of
HSAS. Although Dow was aware of these
potential problems, for the purpose of this
project, a robust pretreatment section (or
any other measure in the unit) was not
considered to minimize the level of these
impurities and their impact, except for the
use of a proprietary antifoamb
.
FIG. 5 shows that the unit had stable
operation during Exp. 1 with BFG only
(black and blue data points) and during
the run in which BFG was mixed with
COG. However, when only COG was
processed, unit performance showed a
rapid decrease over a period of 1 wk. The
red data points show a lower CO2
capture
efficiency and a period of unstable operation
because of foaming issues in the system.
However, the primary cause for this
unstable operation was continuous foaming
and fouling of the unit due to the presence
of naphthalene, tars and oils in the
COG that condensed in the absorber. The
continued accumulation of these impurities
resulted in unit fouling, which was reflected
by a high pressure drop across the
absorber column and downstream equipment,
such as heat exchangers and coolers.
A unit shutdown took place after
Exp. 1, and the unit was opened for maintenance.
Process forensics indicated significant
fouling in several sections of the
unit. The nature of the fouling was identified
with several analyses, such as elemental
analyses of deposits, microscopy of
solid residues and GC-mass spectrometry
of organic liquids. Based on these results,
it was confirmed that aromatic tars from
the COG were present in the installation.
These are known to cause foaming and
fouling in various gas-liquid separation
processes when they condense in the colder
parts of the unit (e.g., post-compression
coolers). Evidence of foaming was also
found on the packing that was loaded into
the absorber and stripper column.
Additional design features could improve
the feedstock purification, such as
an upstream pretreatment (washwater column)
or other measures in the unit (skimFIG.
7. Buildup of degradation products (i.e., the sum of bicine + THEED + hydroxyethyl ethylene
urea + HEED) during Exp. 1 (black data points) and Exp. 2 (blue, purple and red data points)
as a function of time. Note: Detection limit is ~100 ppmw.
Hydrocarbon Processing | OCTOBER 2022 21
ming systems), especially on the highpressure
side of the unit. Furthermore, the
preventative use of the proprietary antifoamb
would
have helped to mitigate the
negative impact of the feed gas impurities.
However, such improvements were out of
scope for this work; therefore, it was decided
to discontinue operations with COG.
In case COG were utilized as a source of
H2
in steel gas valorization, it was anticipated
that, with adequate design considerations,
the naphthalene, light oil and tar
content of such gases could be addressed.
Tar and light oil are not the only contaminants
that can impact utilization potential.
Steel gases like BFG, BOFG and
COG also contain a significant number of
contaminants, such as ammonia (NH3
HCN, H2S, carbonyl sulfide (COS) and
),
carbon disulfide, as well as metals such as
iron, mercury and arsenic10,11
and traces
of O2
. These can affect the operations directly
or indirectly, and a major objective
of this study was to assess that impact as a
function of time. During operations, liquid
samples were extracted from the amine
circulation at a frequent rate. Typically, a
250-ml liquid solvent sample was collected
every 72 hr from the unit. These samples
were analyzed at Dow's laboratories.
Analysis results were used to control
the amine concentration in the solvent
within a target band of 40 wt%-50 wt%.
Water-and occasionally amine-was
added to the system to replace the water
lost from the system.
More interestingly, the chemical composition
of the liquid circulation provided
an indication of the impact of the treated
gas on the composition of the solvent. An
extensive list of organic and inorganic species
was monitored, along with important
parameters such as pH, color, density and
acid gas loading. It should be noted that
contaminants in the gas can also cause
indirect damage, as they can be converted
into other more harmful species upon the
chemical reactions caused by the basic
nature of the solvent, the temperature in
the installation and the presence of metals
that might catalyze these side reactions.
It was clear from the regular solvent
analysis that, despite the relatively poor
quality of the BFG (blue and black data
points in FIG. 6), the buildup of HSAS was
found to be steady, but slow. A somewhat
higher rate of formation, although still not
critical, was observed when COG was cofed
with the BFG (purple data points)
or fed on its own (red data points). The
faster growth of the HSAS concentration
in these experiments was directly related
to the higher concentration of contaminants
in the COG. Based on the pilot
plant data and operational experience, it
was found that untreated COG cannot
be fed directly to an amine absorption
unit without having a significant impact
on the process economics from a capital
expenditure perspective (implementation
of purification equipment) and an operational
expenditure perspective (solvent
and energy use). It should be noted that
Exp. 2 was terminated because of fouling
issues. The upper limit for HSAS was not
reached during this experiment.

Hydrocarbon Processing - October 2022

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