Hydrocarbon Processing - February 2022 - 42

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ture to increase, provided there is hydraulic
capacity in the downstream SRU to
handle the additional water vapor in the
SWAG stream. In practice, capacity in the
water feed-effluent exchanger should also
be verified prior to co-processing.
With less residence time in the upstream
separator vessels on the diesel
hydrotreaters (due to significantly increased
water being generated in these
units), there will be more hydrocarbons
in their sour wastewater. A liquid-liquid
coalescer may be required on this stream.
The impact of additional organic acids in
the sour water due to co-processing (e.g.,
phosphates) was not considered. In practice,
if the level of additional organic acids
is significant, caustic can be injected
to neutralize them.
The refinery's main amine system
uses DEA, which is common in many refineries.
TABLE 5 details the impact of coprocessing
on key parameters. The table
includes a case where the DEA solvent is
replaced with an MDEA solvent, which
preferentially absorbs H2
S over CO2
.
Typically, in amine units, the limits
on the exchanger duty design are
reached before system hydraulics. The
extra CO2
absorbed by the DEA, with
co-processing, requires more reboiler
duty (50 psig stripping steam in this
study) to regenerate the amine and,
hence, additional condenser duty in the
top of the stripper column. In this case,
4%-5% more reboiler and condenser
duty were needed. This should not be a
problem for systems not near capacity;
TABLE 6. SRU key parameters, crude only vs. co-processing operation
Modified Claus unit
Parameter
Acid gas flowrate, kg/hr
Recycle acid gas flow, kg/hr
Total acid gas flowrate, kg/hr
SRU total feed H2
SRU total feed CO2
SRU total feed NH3
S, vol%
, vol%
, vol%
Reaction furnace
temperature, °C
CO2
in Claus tail gas, °C
Claus tail gas flowrate, Nm3
Claus sulfur recovery, %
/hr
-
5,650
68.5
8.3
12.8
1,299
2.6
14,270
97.39
6,120
-
5,650
553
11.6
1,253
4.6
14,484
97.3
6,203
66.5
11.3
12.1
1,271
3.6
14,663
97.25
Modified Claus unit + TGTU
Crude oil only Co-processing Crude oil only Co-processing
5,650
6,120
873
6,120
64
14
6,993
60.7
18.6
10.7
1,214
6.5
15,066
97.13
TABLE 7. TGTU amine section key parameters, crude only vs. co-processing operation
Co-processing
Parameter
Absorber inlet flowrate, kgmol/hr
Absorber inlet CO2
Absorber inlet H2
Absorber outlet H2
Absorber CO2 slip, %
Amine flowrate, m3
Amine strength, wt%
H2S rich loading, m/m
CO2 rich loading, m/m
Stripping steam, kg/hr
Condenser duty, MW
AAG H2S, vol%
AAG CO2, vol%
, %
S, %
S, ppmv
/hr
Crude oil
only
455
6.46
1
139
70
41
40
0.036
0.061
2,620
0.43
32.45
62.21
42 FEBRUARY 2022 | HydrocarbonProcessing.com
Co-processing
(no change
in TGTU)
475
10.98
1
500
75
41
40
0.036
0.094
2,620
0.38
24.14
70.59
(TGTU optimized-
high circulation)
475
10.98
1
150
74
45
40
0.033
0.089
3,100
0.54
24
70.72
however, many older amine systems are
already operating at capacity-often because
utilities have not been expanded
at the same rate as refinery capacity-
and, for these systems, some equipment
capital investment may be required.
Alternatively, the solvent could be
changed to MDEA.
Switching to an MDEA solvent has advantages
in terms of energy consumption
and improved H2
S:CO2 ratio in the AAG,
which limits the need for downstream
modifications of the SRU. However, this
is not the only consequence of changing
to MDEA, and the effects on other units
in the refinery need to be considered before
a system-wide conversion.
The refinery's SRU, which processes
both SWAG and AAG, was modeled
under two different cases: a two-stage
Claus only and a two-stage Claus with
an amine-based TGTU. The results are
provided in TABLE 6. All cases used DEA
in the upstream main amine system. The
most obvious change in the SRU is the
increased CO2
concentration in the feed
acid gas when co-processing. The volumetric
flow through the SRU increased
by 2%-3%, which is minor. The Claus
section's sulfur recovery efficiency declined
by 0.1%, mainly due to the decrease
of H2
er reaction furnace.
As expected, an increase of CO2
S in the acid gas and the coolin
the
feed reduced the reaction furnace
temperature. It should be noted that the
temperature presented in TABLE 6 is an
adiabatic temperature and does not consider
heat losses, which means that the
actual temperature of the furnace during
co-processing is expected to be less than
1,250°C. As discussed in the SRU section,
maintaining the reaction furnace
front zone temperature at, or hotter than,
1,250°C is critical for complete destruction
of feed contaminants.
If the reaction furnace is equipped with
a two-zone chamber, then the acid gas bypass
fraction to the rear zone can be increased
to maintain the front-zone hotter
than 1,250°C. In this case study, the bypass
fraction must be between 10%-50%
of the inlet acid gas flow for maximum
temperature to destroy the contaminants
(FIG. 11). The upper limit is based on typical
refractory thermal limitations.
As discussed in the SRU section, if
the furnace has a straight-through design,
the furnace temperature can be
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