Hydrocarbon Processing - December 2020 - 38

Plant Design, Engineering and Construction
The loss of material base due to corrosion was distributed to
the absorption units in the DCU and hydrotreating (HDT)
unit. During this corrosion process, the scrubber in the DCU
began to show symptoms of an increase in differential pressure,
until a drag of amines happened for the first time in the preheating drum sequence. An alert was provided to check operations, and a gamma scan analysis detected that the packaging
did not have a uniform distribution of the liquid (DEA), most
likely due to plugging of the passage areas by the solid particles
present in the amine (FIG. 3).
Amines were sampled to determine the source of the solids,
and the results again eliminated the suspicions that the DCU
was the source of iron coming from the regenerator reboiler.
The effect of the reboiler corrosion on the fuel gas scrubber
impacted its operation, and without an immediate solution this
would continue to increase. A team was formed to improve the
amine quality, but this process was not advancing fast enough
to avoid a wider plugging of the scrubber, which required taking the scrubber out of service to change the inner packing.
Design review. Due to imminent plugging in the short term,
a quick design review of the gas system treatment of the DCU
was performed. This review immediately revealed the zero operational flexibility of the gas treatment system in case of failure. The design considers that in a failure event in any relevant
equipment, the entire system must be taken out of service for
repair. In the DCU, this involves a bypass. Rather than removing the entire system from service, block valves would need to
be added on the lines and equipment to isolate and remove
only the scrubber.

FIG. 3. Gamma scan of a scrubber column.

DECEMBER 2020 | HydrocarbonProcessing.com

Given these challenges, the maintenance team considered
removing equipment and washing and/or vaporizing circuits
attached to the scrubber, making the time and scope of the gas
system delivery even more extensive. This impacted the initial
optimistic planning schedule and required operational tasks
and maintenance of at least 15 d, which included: DCU to bypass, fluid displacement of circuits of the system gas treatment,
extraction of the scrubber equipment, vaporizing, removal of
inner packing, cleaning of the tower, inspection to verify minor
details, loading of inner packing, closing the scrubber, vaporizing, inventory, commissioning and startup of the DCU.
The shutdown of the DCU had significant economic impact on the refinery margins. The refinery manager sought
other ways to approach the work without such a high impact.
This was a key moment in reframing the problem to " reduce
the time of all processes in cleaning the scrubber tower. " Accepting the original frame keeps the same solution in place,
rather than finding options within the cleaning process to reduce the shutdown time-a partial shutdown, reducing the
time for unloading and loading the inner rings of the packing
beds by contracting a specialist company, increasing the work
to a continuous 24-hr model, etc. Another option is to break
the frame and look outside the traditional framework to rethink the goal. Feed to the coker was taken down slightly to
make space to treat the external gas in the fuel gas scrubber,
so an assessment was ordered for the scrubber delivery. First,
the unit's ability to send the untreated gas (sour gas) to other
units was evaluated. One option was to build a long pipeline.
Using one of the existing pipelines with smaller diameters affected the ability of other units to treat sour gases. During the
evaluation of alternatives, it was determined that the liquefied
petroleum gas (LPG) contactor showed no trace of contamination and was operating properly.

FIG. 4. LPG contactor and fuel gas scrubber.

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Hydrocarbon Processing - December 2020

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