Hydrocarbon Processing - February 2022 - 41

Bio-Based Processing
COS and CS2
species will hydrogenate to H2
cycled to the front of the SRU.
will be eliminated, as these
S and be reImpacts
on the TGTU. Today's strict SO2
emissions requirements are beyond the
capabilities of the Claus process. The tail
gas cleanup unit is a common addition to
adhere to the new guidelines. Tail gas units
include processes such as sub-dewpoint,
direct
amine absorption and stack SO2
oxidation, hydrogenation with
recovery.
The Claus tail gas hydrogenation process
followed by amine absorption-called a
TGTU-is the most popular choice when
more than 99.5% sulfur recovery efficiency
is required.22
processing on TGTUs is important not
only due to its prevalence in refineries, but
also because the acid gas from the regenerated
amine is recycled to the reaction furnace.
Alternate tail gas processes, such as
sub-dewpoint or direct oxidation, are not
discussed in this article because the changes
brought about from biofeed co-processing
are minimal, apart from those that have
been discussed in the SRU section.
In a TGTU, the Claus tail gas is first
reheated and processed in the hydrogenation
reactor in which all oxidized sulfur
species (SO2
, COS and CS2) and the reS
on the surface of
maining elemental sulfur are hydrogenated
or hydrolyzed to H2
cobalt-molybdenum catalyst. The hydrogenated
process gas is then cooled through
an exchanger and water quench column
and then treated in the amine absorber.
The rich amine is pumped to the regenerator,
where the acid gas species are stripped
from the solvent and recycled back to the
SRU reaction furnace. The TGTU amine
is typically a selective amine (most commonly
MDEA) that is optimized to minimize
CO2
the CO2
absorption, which minimizes
recycled to the SRU.
With biofeed co-processing, the composition
of the tail gas of a well-operated
Claus unit is expected to be like the original
case, except for an increase in CO2
While the extra CO2
.
will pass through the
hydrogenation section of the TGTU, the
increased CO2
in the feed will increase its
recycle will, therefore,
pickup by the amine, and the rich amine
loading and CO2
also increase. To maintain optimum performance,
the amine circulation rates or
amine strengths will need to be adjusted
or a switch to a more selective amine
chemistry may be required.
Installing acid gas enrichment
(AGE). To maintain hydrotreater catalyst
activity, a certain amount of sulfur is
needed in the feedstock. This is primarily
of concern in the HVO production route,
where there is not always sufficient sulfur
naturally in the hydrotreater feed to do
this. This can be overcome by the addition
of a sulfiding agent, such as dimethyl
disulfide (DMDS), to the hydrotreater
feed; however, continuous addition can
be expensive, and sulfiding agents are often
difficult (and unpleasant) to store and
handle. One solution is to install an AGE
unit that can concentrate the H2
S from
The impact of biofeed cothe
amine process and recycle it to the
hydrotreater, keeping the catalyst active.
The installation of an AGE unit design is
a decision that can be advantageous for
some facilities. More facility details on
where AGE systems have been installed,
as well as the rationale for their installation,
are provided in literature.23,24
CASE STUDY: FICTIONAL
EXPERTS REFINERY
The fictional 100,000-bpd Experts
Refinery has been built for maximum
diesel yield, and generally processes highsulfur
crudes. The process conditions are
Parameter
loosely based on the field test results of
several operating refineries optimized for
diesel yield. The SWS and amine plants
were simulated on a proprietary gas treating
simulation toola
, while the SRU and
TGTU were simulated on a process simulation
softwareb
. The authors have found
that these two programs yield the best accuracy
of the respective simulated units.
The Experts refinery has two diesel
hydrotreaters (cracked and straight-run)
and co-processes 10% biofeedstock in
both. This has an impact on the treating
units in several ways. A comparison of
normal and co-processing operation is
provided in TABLES 4-7.
The key parameters for the SWS
unit are shown in TABLE 4. In this case, a
stripped water specification of 50 ppmw
ammonium ions is desired. To meet this
specification with biofeed co-processing,
stripping steam was increased by 23%.
Much of this steam was required to process
the additional water volume. The additional
steam also required more reflux
condenser capacity with the associated
condenser duty to reduce the SWAG temperature
to 85°C, which had increased by
25%. While many facilities will not have
this ability, this duty can be offset to an
extent by allowing the overhead temperaTABLE
4. SWS key parameters, crude only vs. co-processing operation
Crude oil only
Sour water volume, m3
Sour water CO2, mg/l
SWAG CO2, vol%
SWAG flow, tpd
Stripping steam, kg/hr
Condenser duty, MW
70
1,500
3.2
42
14,200
5.6
Co-processing
85
3,500
8.6
47
17,500
7
Parameter
TABLE 5. Main amine system key parameters, crude only vs. co-processing operation
Crude oil only, DEA
DHT hydrogen CO2
DHT hydrogen H2
Non-DHT H2
Non-DHT CO2
, %
S, %
S, kmol/hr
, kmol/hr
H2S-rich loading, m/m
CO2-rich loading, m/m
Stripping steam, kg/hr
Condenser duty, MW
AAG H2S, vol%
AAG CO2, vol%
AAG flow, kg/hr
1.5
107
18
0.32
0.04
23,000
5.4
84
10.5
5,650
0.5
1.4
Co-processing, DEA Co-processing, MDEA
0.5
1.4
107
18
0.32
0.07
24,000
5.7
78
16.5
6,120
107
9
0.25
0.02
20,000
5.2
86.9
7.87
5,470
Hydrocarbon Processing | FEBRUARY 2022 41
Hydrocarbon Processing - February 2022

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