Hydrocarbon Processing - February 2022 - 43

Bio-Based Processing
managed with oxygen enrichment or cofiring.
FIG. 12 shows the reaction furnace
temperature profile for a combined acid
gas feed (main amine system and TGTU
recycle streams), which contains 22.4%
CO2
because of co-processing. In this
case, the model shows that the minimum
required temperature of 1,250°C in the
reaction furnace can be easily achieved
with low-level oxygen enrichment without
other changes.
In the case of co-firing, it was assumed
that the fuel source is a pure methane
natural gas. Simulation shows that the introduction
of the co-processed acid gas
increased the volumetric flow in the SRU
by 2.3%, which should be accommodated
in the existing plant. However, every
5 kmol/hr increase of natural gas, which
is approximately 3% of the feed acid gas,
resulted in an 8% increase in combustion
air demand (or air flow requirement).
This is equivalent to a decline in SRU
sulfur inlet capacity of approximately
6%. For this case study, the required
temperature in the reaction furnace was
achieved by introducing natural gas at
8% of the feed acid gas-this caused an
18% reduction in SRU capacity. This
value will vary depending on the actual
feed composition, operating parameters
and capacity. FIG. 13 shows the impact of
the natural gas co-firing on SRU capacity
and air demand.
The modeled TGTU amine system
uses 40 wt% MDEA with a standalone
regenerator. Although the optimized
CO2
can reach 85% slip, factors such as
solvent over-circulation or the formation
of primary and secondary amines from
MDEA degradation will increase CO2
pickup in the amine absorber. Therefore,
the TGTU is modeled assuming a more
conservative 70% CO2
slip correlates to less CO2
in the
FIG. 12. Oxygen enrichment concentrations vs. front-zone reaction furnace temperature.
slip. The effect of
the TGTU amine unit performance on
the reaction furnace temperature is demonstrated
in FIG. 14. As expected, increasing
CO2
combined AAG (and total feed gas) and
a hotter reaction furnace.
The TGTU amine absorber inlet contained
70% more CO2
in the co-processing
case than it did in the crude oil-only
case. This resulted in greater rich loadings
and more H2
S leaving in the absorber
vent gas. The rich loading could be reduced
by increasing the amine circulation
or by increasing the amine strength, or
both. Increasing the circulation requires
FIG. 13. Natural gas co-firing vs. the impact on air demand and SRU capacity.
Hydrocarbon Processing | FEBRUARY 2022 43
more energy consumption to circulate
and regenerate the amine. Increasing the
strength requires more amine inventory
and additional energy to strip the amine.
TABLE 7 shows the optimized case with
increased amine concentration, which required
17% more steam to regenerate the
amine. It should also be noted that, when
operating with high amine concentrations,
the amine losses will also increase.
Therefore, when optimizing, operators
should consider their requirements and
available resources (such as pump capacity,
amine inventory and steam capacity).
Takeaways. The impact of biofeed coprocessing
on downstream treatment
units can be quantified with a well-designed
test run, appropriate gas and liquid
analytical capabilities, and reliable process
simulation. Based on this, a fit-forpurpose
treating scheme that minimizes
capital and operational expenditures and
prevents unanticipated reliability issues
can be designed and implemented.
A major component in the changes
associated with biofeed co-processing is
the additional water produced. This will
usually require modifications or increases
to the SWS system. If these are intelligently
implemented, refinery freshwater
requirements can often be significantly
reduced. The additional water volume
increases the unit's stripping steam requirement
and will likely reduce the residence
time of the water-liquid hydrocarbon
separation vessels, which potentially
will leave more liquid hydrocarbon in the
wastewater. The total hydrocarbon content-or
worse, a fluctuating content-
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