Hydrocarbon Processing - April 2022 - 20

Maintenance and Reliability
can only assist in removing hydrocarbons
from the amine. Engineering staff also
made the decision to continuously purge
2 gpm from the reflux accumulator as a
method to continuously remove hydrocarbons
and other foaming species from
the amine.
Reflux accumulator sizing. The reflux
drum is a horizontal 2 ft-diameter drum,
which was not overly effective at stopping
foam once it rolled out of the column.
There is a roughly 9-ft2
area for gravity-assisted
vertical separation in the regenerator
upstream flowing into a horizontal 2-ft
piece of pipe for the reflux drum. With
the reflux drum operated half full, there
is roughly 1.5 ft2
otherwise, due to their influx from
the reformer hydrogen.
Takeaways. The following are the primary
takeaway points from the investigation
of foaming in the TGTU:
* The root cause of the foaming
was identified from the lab
measurements as fatty acids from
rust inhibitors or metalworking
additives. The authors believe that
iron sulfide particles were acting to
stabilize foam in the regenerator.
Removal of the iron sulfide
of flow area, and gravity
is working at a 90° angle to the gas flow.
Foaming event mitigation was not considered
in the design of the tail gas unit, but
this should be considered for future Phillips
66 designs. The tail gas reflux drum
does not include a hydrocarbon skim.
Summary
of
operating improvements.
After these collective learnings,
several improvements were implemented
at the refinery, including:
* Increasing steam to the reboiler
to target 120°C (248°F) on
regenerator overhead. This move
was made to decrease lean loading in
amine, reduce iron-sulfide particle
generation, and decrease H2
S vapor
pressure over the lean amine to
reduce stack SO2
emissions.
* Adding antifoam injection points,
so that antifoam does not have
to pass through carbon beds and
extra piping and equipment in the
rich amine before entering the
regenerator.
* Reducing amine circulation through
carbon filters, so that amine flow was
within design rates. Carbon filters
for the new TGTU were installed
on the rich amine piping. Carbon
can be used to remove contaminants
that cause foaming (e.g., fatty acids),
and it can also remove submicron
iron-sulfide particles, per Phillips 66
lab measurements.
* Establishing a constant purge rate of
2 gpm from the amine regenerator
overhead accumulator to remove
contaminants from the system. The
purge rate helps to remove heavy
hydrocarbons that might accumulate
20 APRIL 2022 | HydrocarbonProcessing.com
particles, along with fatty acids, has
mitigated foaming considerably.
The removal of only iron sulfide
may reduce foam stability, but it is
not the root cause of foaming itself.
The MDEA still needs a foaming
agent-in this case, fatty acids-
to exhibit the foaming shown.
* New equipment in amine service
should be rinsed with alkaline
material to remove lubricants from
the new equipment. Operating
companies have recommended
low-strength caustic (< 10 wt%
NaOH) for years. The amine
columns were only rinsed with hot
condensate before this startup.
* Reducing steam to the amine
regenerator reboiler to mitigate
foamovers or " burping " liquid
overhead can be worse than
the foaming itself. Improperly
regenerated amine can lead to
emissions excursions, just as
foaming does. Phillips 66 has
found that operating tail gas amine
regenerators with a target overhead
temperature of 118.33°C-121.11°C
(245°F-250°F) is a reliable way
to control contaminants that
lead to foaming in tail gas amine
regenerators.
* Antifoam injection facilities must
be provided to both absorbers and
regenerators, as antifoam should not
have to travel through an activated
carbon bed to reach a column.
* It is not clear what advantage having
a trayed regenerator vs. a packed
regenerator provides in a tail gas
unit, especially when the column
diameter is only 3 ft. Phillips 66's
operational experience has been that
a trayed regenerator is more likely to
foam than the packed regenerator.
Industry experts suggest that packed
towers can reduce the likelihood of
foaming in the tail gas regenerator,
provided there is proper liquid
distribution. One further
consideration is that, with large
amounts of colloidal iron sulfide
particles present, it is possible that
packing would foul quickly, resulting
in reduced separation efficiency in a
packed amine regenerator.
* Activated carbon beds can be used
to remove submicron colloidal iron
sulfide particles. Although this is
not desirable to the hydrocarbon
removal capacity of the carbon beds,
it is an effective stop-gap measure
that can be considered to help
preserve amine inventory.
NOTES
a Eurecat's TOTSUCAT process
b Calgon Carbon Corp.'s Sorbamine, AT 4x10
SAM COPPER is a Process Engineer with Phillips 66,
working with crude and vacuum distillation, saturate
gas distillation and diesel hydrotreating. Mr. Copper
has spent most of his career focused on operations
engineering, but also has experience in process
design, energy conservation and capital project
startup support. He earned a BS degree in chemical
engineering from Tulane University in New Orleans,
Louisiana.
JESSE CONTRERAS is a Special Projects Chemist
with Phillips 66. He leads the process chemistry team,
performing analytical forensic investigations to address
challenging operational problems. Dr. Contreras has a
Bch degree in chemical engineering from Universidad
de los Andes in Colombia, along with an MS degree in
chemical engineering from the University of Dayton in
Ohio. He earned his PhD in analytical chemistry from
Brigham Young University in Utah.
LEONARD NYADONG is a Senior Scientist in
Phillips 66's Energy Research and Innovation (ERI)
organization. He has more than 10 yr of experience in
the petroleum industry, developing and implementing
advanced analytical methods to support Phillips 66's
ERI and worldwide organizations. He earned a BS
degree in chemistry and materials science technology
from the University of Buea in Cameroon, an MS
degree in biochemistry from the University of Toledo
in Ohio, and a PhD in analytical chemistry from the
Georgia Institute of Technology in Atlanta.
JASON STAVROS is the Director of Sulfur Processing
at Phillips 66. He is a chemical engineer with 30 yr
of experience in the petroleum industry, primarily
in operations engineering and process design.
Mr. Stavros earned a BS degree from Carnegie
Mellon University in Pennsylvania.
NATE HATCHER is an Engineering Consultant with
Optimized Gas Treating (OGT). He has more than 25 yr
of experience in gas treating and sulfur processing.
At OGT, he led the development of the ProTreat® and
SulphurPro® process simulators before assuming
his current role. Mr. Hatcher earned a BS degree in
chemical engineering from the University of Kansas.
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