Hydrocarbon Processing - October 2022 - 32

Plant Safety and Environment
and some condenser inlets
* Low-temperature solid sulfur/
liquid water contact corrosion
° Typical corrosion rates of
50 mil/yr-70 mil/yr2
° Can be as high as 500 mil/yr,
depending on conditions
and species present2
° Most common in condenser
outlets and in liquid sulfur
collection and storage, and
can occur anywhere the
metal temperature falls below
119°C (246°F), which is the
freezing point of sulfur
* Sulfuric acid (SO3
) corrosion
° SO3 is not normally present in
SRU gas streams, due to the
reducing chemistry of the process
° Most SO3 is created in
the incinerator under
oxidizing conditions
° Has a dewpoint (condenses
as liquid sulfuric acid) that
depends on concentration;
dewpoint ranges from
90°C-200°C (194°F-392°F)3
° Depending on pH,
corrosion rates can be
more than 100 mil/yr
* Water-side corrosion4
° Various corrosion mechanisms,
including oxygen and
alkalinity, among others
° Corrosion rates depend on the
mechanism and can be very rapid.
The author's company's case studies
include hundreds of corrosion incident
investigations and number around
25/yr-30/yr, making corrosion the most
common failure mechanism category.
High-temperature H2
S corrosion (most
commonly on WHB tube sheets and
WHB outlets) and low-temperature frozen
sulfur contact corrosion (most commonly
on condenser outlet pipes and
sulfur storage vessels) are by far the most
numerous and are relatively equally represented
in the case files (10/yr-12/yr).
This indicates that, despite the constantly
improving understanding of these corrosion
mechanisms and how to avoid them,
they continue to be extremely prevalent.
Most of the recent case studies have found
that the SRU design is not usually the
problem (i.e., vessels and piping are usually
designed to maintain suitable metal surface
temperatures), but that the corrosion
results primarily from poor construction
32 OCTOBER 2022 | HydrocarbonProcessing.com
practices, poor maintenance, and poor understanding
by plant personnel of the importance
of skin temperature regulation.
SO3
corrosion case studies are less
prevalent, averaging around 2/yr. The
most common location for this type of
corrosion is in heat exchangers located
downstream of the incinerator, where
the exchanger tube wall temperatures can
easily drop below the SO3
dewpoint, although
corrosion of the incinerator stack
and the incinerator emissions analyzers
have also been noted at many locations.
Water-side corrosion is the least prevalent
in the case files, with only a handful
of incidents determined to be definitively
linked to water-side corrosion mechanisms
alone. This may be because water
quality is usually carefully monitored and
adjusted at most facilities by outside water
treatment specialists, and because the
other three process-side corrosion mechanisms
are simply more likely. Regardless,
water-side corrosion does occur and must
still be treated properly in the design and
operation of the SRU.
Incident investigations for corrosion
failures should always begin with the exact
location of the failure (i.e., the hot end
or cold end of a condenser or WHB tube)
and include detailed photographs and inspections
of the failure areas. Water-side
corrosion failures can often be easily distinguished
from process-side corrosion
with a visual determination from which
side the corrosion progressed-while
high-temperature H2
S corrosion and
low-temperature wet sulfur contact corrosion
can often be distinguished by the
operating temperature and conditions
at the exact failure location. SO3
corrosion
can often be easily identified by the
presence of a green iron sulfate corrosion
product that is not present with other
mechanisms, and by the fact that it can
only occur downstream of an oxidizing
location (e.g., an incinerator). Unfortunately,
many incident investigations only
begin after the corroded areas or vessels
have been removed and replaced without
detailed examination, meaning that the
most likely root cause must be estimated
based on a process review only.
Regarding corrosion prevention, the
following recommendations are associated
with the most common root causes:
* High-temperature H2
° Ensure proper design, installation
and maintenance of refractory
S sulfidation
and ferrules in high-temperature
SRU areas-areas that will,
or might, operate hotter than
300°C (572°F). Refractory
and ferrule design should
be conducted by competent
personnel and should ensure that
metal surfaces will be below this
temperature limit where possible.
Installation and maintenance
of these materials should also
be conducted and supervised
by competent personnel with
strong experience in these areas.
Following the installation of
these materials, it is important
to use proper dry-out/curing
procedures as recommended
by the material supplier.
° Utilize proper operating
procedures that will not
damage the refractory and
ferrules, especially during
high-temperature operating
conditions like fuel-gas firing
(e.g., startups, shutdowns and
hot standbys) and oxygen
enrichment conditions. This
includes operating procedures
that will avoid overheating or
melting these materials, and
which are usually based on a safe
maximum temperature (allowing
for measurement errors and
temperature variabilities) of
around 1,550°C (2,732°F).
This also includes procedures
that will avoid thermally shocking
the materials-usually defined
as heating/cooling them faster
than the normally recommended
maximum of 50°C/hr.
° Measure reaction furnace
refractory wall (as opposed
to process gas) temperatures,
usually through a specialized
full-time thermocouple located
at the refractory wall or through
a pyrometer designed to
measure refractory temperatures.
Temporary thermocouple
installations can also be used
where appropriate, especially
during low-temperature startup
conditions. Finally, simulations
can be used to determine process
temperatures based on process
conditions and can be used to
confirm conditions that might
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