Hydrocarbon Processing - January 2022 - 63

Bio-Based
Processing
P. LE GRANGE, K. TEKEBAYEV, L. GOETTLER
and J. KIEBERT, Sulphur Experts, Katwijk aan Zee,
Netherlands; and M. SHEILAN, Amine Experts,
Calgary, Alberta, Canada
Impact of biofeed retrofits, coprocessing
on refinery amine units, SWSs and SRUs-Part 1
Diesel with a portion of biologically
sourced carbon is being produced at an
increasing number of conventional crude
oil refineries. This is being done by coprocessing
biofeedstocks in refinery hydrotreaters
and fluidized catalytic crackers
(FCCs) or through the installation of
a dedicated biofeedstock hydrotreater to
produce commercial biodiesel products.
Generally, refineries are looking to technologies
that allow them to easily incorporate
biofeedstocks into their existing
infrastructure. This article describes the
impacts that this incorporation has on
a refinery's existing amine system, sour
water stripper (SWS) and sulfur recovery
unit (SRU), which are used to remove
toxic contaminants from the hydrocarbon
products, waste vapors and wastewater
in the refinery. It also presents some of
the operational and design options available
to manage those impacts, as well as
a specific case study. This article focuses
on the operational changes in, and challenges
for, amine, sulfur and sour water
units in conventional oil refineries due
to biodiesel production. This information
will be useful for readers looking to
predict the impact on these units or to resolve
an operational issue resulting from
biofeedstock coprocessing.
Refineries,
Toxic hydrogen sulfide (H2
meet biofeedstocks.
S) is present
in hydrogen recycle streams, hydrocarbon
products, effluent gas and water streams.
Refineries must use a treatment scheme
(FIG. 1) to remove it-a system that is
mostly standardized across conventional
refineries in service worldwide. The H2
carbon dioxide (CO2
(NH3
S,
) and ammonia
) are removed from hydrogen and
hydrocarbon streams by water washing
and amine solvent scrubbing. The
amine and water are then stripped by using
steam, and the resulting concentrated
stream of H2
S, CO2 and NH3
and H2
is treated in
a modified Claus plant commonly called
an SRU. In the SRU, the H2
S is converted
to elemental sulfur, and most of the NH3
is broken down to N2
O. CO2
passes
through the unit largely unreacted. The
liquid sulfur product is further treated
and then sold to the fertilizer and sulfuric
acid industries. Many refineries will have
an additional amine unit-a tail gas treating
unit (TGTU)-to recover more H2
and sulfur dioxide (SO2
tail gas to reduce SO2
S
) from the Claus
emissions to the
atmosphere. While the general scheme
is common to most refineries, there are
many variations in configuration, technology,
solvent type and equipment
within the amine treating and SWS units,
and also within the SRUs and TGTUs.
H2
S degassing of the liquid sulfur product
is not affected by biodiesel coprocessing
and, as such, will not be covered in this
article. Similarly, the impacts of biofeed
coprocessing on the SRU incinerator are
minor and can be disregarded.
With stricter limits on CO2
emissions
associated with conventional fuels,
bio-based waste oils (such as vegetable
oils and liquid intermediates of biomass
conversion) have become an interesting
subject as an alternative energy source
for energy companies. One advantage of
bio-based oils vs. crude oil is their low
sulfur content; however, their high oxygen
content (TABLE 1) presents several
processing challenges.
Vegetable oils are the most common
biofeedstock in oil refineries. They consist
of triglycerides and fatty acids, which contain
oxygen in their molecular structure.
The presence of oxygen means that these
components are already partially oxidized,
so their energy density is lower. Although
FIG. 1. Conventional refinery treatment scheme.
Hydrocarbon Processing | JANUARY 2022 63
Hydrocarbon Processing - January 2022

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