Hydrocarbon Processing - March 2021 - 54

Process Optimization
TABLE 2. HETP comparison-Actual operation
Parameter
Packing type

Actual HETP, in.
Vendor/literature
published HETP, in.
Ratio of actual HETP
to published HETP
Ratio of SME-designed
HETP to published HETP

Source 1

Source 217

Source 34

Smalldiameter, ringtype packing

1-in. ring

1.5-in.
specialty

More than 34

~ 17

15, 17, 19

20, 16

More than 2

0.9, 0.8, 0.7

1.1, 1.3

~ 1.8-2.4

large liquid openings in the side walls of the trough
(either rectangular-notched or round holes) have given
good service in this application.
2. Packing should be an open design without small
openings to minimize the potential for fouling of the
packing. The major packing vendors offer such open
packing, with some explicitly marketed for SWSs.
3. HETP values published in vendor literature, or
correlations provided in literature, should not be used
directly for estimating required packing bed depth. It
is necessary to consider the potential for fouling and
efficiency loss in the SWS packing. Although some
SWSs have experienced actual HETPs approaching
vendor/literature HETP values, it is suspected that
those systems were fed sour water that was cleaner
than is typically found, perhaps due to practices like
those mentioned in the next point. Experience and
good engineering judgment must be used in estimating
HETP values that will be experienced in the end, which
should include evaluation of the mass transfer.
4. Sour water feed conditioning systems are likely even
more critical for a packed SWS than they are for a trayed
SWS. Adequate three-phase separation in all separators
in the process (even in the reflux drum, if installed) is
recommended. Adequate settling time in the sour water
surge tank is also recommended, in addition to the
particulate filter and liquid coalescer.
Issues encountered in operation. A wide range of operating problems can occur in an SWS system. A select few are discussed in the following subsections.
Fouling of SWS internals. SWS internals can foul from
many different materials. Corrosion products can accumulate
on the tray or in the packing and cause fouling.
Even with all the preventive measures discussed in Part 1, hydrocarbons and solids may still enter and foul the SWS internals.
It has also been reported in literature6 that, because of the high
vapor pressure of water in the stripper, volatile hydrocarbons will
evaporate with the overhead gas. As a result, removal of lighter
hydrocarbons may make heavier hydrocarbons less soluble in the
water and too viscous to flow properly at the SWS temperature.6
The heavy hydrocarbons collect, along with corrosion particulates and other solids, to form a fouling layer on trays or packing.6
If the SWS is underperforming and other more routine process checks on the system have not identified a cause, then a
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MARCH 2021 | HydrocarbonProcessing.com

gamma scan can be conducted to determine if the internals of
the tower are damaged or severely fouled. A gamma scan generates a density profile of the column that can be used to identify the integrity of internals and column operating conditions.
Scans have shown columns where entire packed sections were
missing or lower than expected. Maldistribution of liquid in the
column can also be demonstrated via the scans. Maldistribution
of liquid in the column will reduce the efficiency of the packing.
Issues with the integrity of tray towers can also be identified.
Maintenance and monitoring requirements. Routine
maintenance and cleaning of equipment may be prudent to remove fouling and particulate, and to improve the run time of
the SWS system. For example, exchangers with bypasses can be
periodically cleaned online. Exchangers used in other processes
that transfer heat between a sour water stream and a hydrocarbon
stream should be inspected for leaks to minimize the potential for
sending hydrocarbon-contaminated water to the SWS system.
The SWS tower could also be washed occasionally if there
is enough storage for the sour water at the plant. Weak acid and
base washes can remove scale, and detergent washes can remove hydrocarbons.7
The hydrocarbon and liquid levels in the flash drum and surge
tank should be routinely visually checked to ensure that they are
at the proper heights and that hydrocarbons are not entering the
stripper. Level controls and interface level controllers in the flash
drum and surge tank should be inspected on a routine basis to
make sure they are working appropriately.
The SWS overhead lines should be periodically examined
for cold areas [less than approximately 82.2°C (180°F)] to prevent salts from depositing. The overhead lines need to be steam
traced and insulated or steam jacketed.
Process instrumentation should be routinely checked for accurate readings to aid in diagnosing potential SWS problems.
The column differential pressure, overhead temperature and
process water flow are important parameters to monitor.7
In some cases, chemical agents (such as dispersants, scale/
corrosion inhibitors and cleaning solutions) may be able to help
control or remove fouling from the residue of hydrocarbons,
salts and corrosion byproducts.
Solid and liquid material from the filter, liquid coalescer or
other equipment could be analyzed to determine the type and
source of fouling. Routine samples of the sour water and stripped
water should also be taken to help identify issues in performance.
Salt solids formation. The formation of salt solids is another
concern in SWSs. For example, in SWSs that remove H2S and
NH3, ammonium bisulfide (NH4HS) solids may form in the
overheads line. When the acid gas condenses, the reflux water
may contain a high concentration of NH4HS, which can lead to
corrosion and salt solids formation. An SWS with reflux usually
has higher concentrations of NH4HS, but pumparound systems
can also be impacted by this type of corrosion.7 Corrosion increases with increasing NH4HS concentration and velocity. Carbon steel is often acceptable when the NH4HS concentration is
less than approximately 2 wt%. Carbon steel is marginal when
the concentration is between 2 wt% and 8 wt%. Above 8 wt%,
carbon steel is generally viewed as unacceptable, and stainless
steel or other higher alloys may be required.18 The overhead temperature is generally kept at or above 82.2°C (180°F) to avoid the
formation of NH4HS solids that can plug lines and equipment.6,19

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Hydrocarbon Processing - March 2021

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