Mitigation of heat exchanger fouling
Detailed analysis of potential contributors identifies the root cause of
fouling in naphtha hydrotreater feed-effluent exchangers
BRUCE WRIGHT Baker Hughes Incorporated
TODD HOCHHEISER Valero Energy Corporation
T
he naphtha hydrotreater
(NHT)
feed-effluent
exchangers at a US refinery were experiencing severe
fouling. The heat exchanger
fouling was limiting run length.
As the preheat exchangers
fouled, the heater inlet temperature declined, resulting in an
increased potential for twophase flow in the heater. Unit
throughput was reduced to
manage the minimum required
heater inlet temperature.
A root cause analysis investigation was conducted to
develop a clear understanding
of the fouling source. This
analysis resulted in the development of an antifoulant
additive treatment programme
that has significantly reduced
the rate of fouling. The antifoulant programme has extended
cycle length and reduced maintenance costs, resulting in a
yearly economic return of over
500%. This article will review
the root cause investigation
steps, results of the treatment
programme and benefits to the
refinery.
Fouling in hydrodesulphurisation (HDS) units can impact
throughput, energy consump-
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tion, and shorten catalyst life.
Deposits form in the feed-effluent heat exchangers and on the
top of the reactor beds. The
economic impact can be severe
from the problems caused by
fouling. Solutions include operational changes, mechanical
upgrades and antifoulant additive treatment to control
specific fouling mechanisms.1
Description of unit
This NHT processes straightrun and coker naphthas from a
combined crude/coker gas
plant. The feed from the gas
plant
consists
of
butane
through jet boiling range material. The NHT feed is
supplemented with purchased
naphtha from an intermediate
storage tank. All feed streams
are mixed in a surge drum and
then pumped to the shell side
of the feed-effluent exchangers.
There are four exchangers in
series. Prior to entering the first
exchanger, the naphtha feed is
mixed with hydrogen. The
feed-effluent exchangers are
designed to fully vapourise the
Hydrogen recycle
compressor
Surge
drum
Minimum
temperature
requirement
Reactor
Furnace
Crude and
coker naphtha
Purchased
naphtha
Feed
effluent
heat
exchangers
Air cooler
Separator
Figure 1 NHT unit diagram
PTQ Q4 2012 1
80
Pre-revamp
Post-revamp
75
U, BTU/hr / SF / ºF
was required to mechanically
clean
the
feed-effluent
exchangers.
70
Root cause analysis steps
and results
65
60
55
50
45
40
35
30
0
50
100
150
200
250
300
350
400
450
500
Days
Figure 2 Heat transfer coefficient pre- and post-unit revamp
naphtha to prevent two-phase
flow in the fired heater. The
vapourised naphtha and hydrogen mixture is heated in the
fired heater to the required
reactor
inlet
temperature.
Sulphur and nitrogen impurities are converted to hydrogen
sulphide and ammonia, respectively, in the fixed-bed catalyst
reactor. The reactor effluent
vapour is cooled and partially
condensed in the tube side of
the feed-effluent exchangers
and reactor effluent air fin
cooler. The liquid and vapour
are separated in a product
separator. The hydrogen gas
from
the
separator
is
compressed and recycled to the
shell-side inlet of the feed-effluent exchangers. The separator
liquid is fractionated in the
NHT gas plant into butane,
light naphtha, reformer feed
and jet fuel. Figure 1 is a schematic diagram of the unit.
Description of problems
A refinery configuration change
altered the boiling range of the
NHT feed from C5 through jet
to C4 through jet. After the
configuration change, the foul-
2 PTQ Q4 2012
ing
rate
of
the
NHT
feed-effluent
exchangers
increased significantly. Figure 2
shows the increased fouling
rate after modifying the NHT
feed to include butanes and
butylenes. The loss of heat
transfer resulted in lower
furnace inlet temperature. A
low furnace inlet temperature
is not sustainable due to heater
fouling caused by two-phase
flow. The reactor outlet temperature was increased to offset
the heat transfer coefficient
reduction by raising the log
mean temperature difference
across
the
feed-effluent
exchangers. The reactor temperature increase was an effective
method of managing the
required minimum furnace
inlet temperature, although an
energy penalty was incurred
for heat lost through the reactor effluent air cooler. As the
feed-effluent exchangers continued to foul, the reactor
temperature could not be
further increased due to
sulphur recombination at a
higher reactor temperature.
Unit throughput was reduced
and eventually a shutdown
In order to understand the
causes of fouling in the NHT, a
root cause analysis approach
was employed that consisted of
system and operations reviews,
deposit analyses, feedstock
analyses and laboratory fouling
studies. These pieces of information were coupled together
to establish the mechanisms
responsible for fouling and to
develop mitigation options.
System and operations
The NHT is configured so that
a combination of straight-run
and coker naphthas are fed hot
to the unit surge drum.
Purchased naphtha supplements the refinery feeds to
keep the NHT operating at
capacity. The majority of the
purchased naphtha is delivered
to the plant via barges and is
contaminated with oxygen. The
purchased naphtha is not
oxygen stripped.
Coker
fluids
commonly
contain reactive compounds,
including olefins, amines and
carbonyls, that can lead to
polymer formation. Some of
these reactions are auto-catalytic in the presence of oxygen.
The best practice for processing
coker naphtha through an HDS
unit is to ensure that intermediate tankage is not utilised,
which would provide time for
polymer reactions to commence.
As such, the configuration and
operation of this unit should
help to minimise the formation
of polymeric deposits. Straightrun naphtha typically has little
impact on HDS fouling unless
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there is a significant influx of
corrosion by-products from the
crude unit overhead system.
Feed to this NHT flows
through the shell side of the
preheat exchangers, while the
reactor effluent flows through
the tube side. This configuration is commonly employed in
hydrotreating units because of
the tendency for ammonium
chloride salts to form in the
reactor effluent at sublimation
temperature and pressure.
These salts must be removed
through online water washing
to maintain the heat transfer
performance of the exchangers. Online water washing of
the tube side of heat exchangers is easier and more effective
than washing the shell side.
Deposit analyses
Visual inspections of the heat
exchangers prior to cleaning
revealed that the tube side was
clean, while the shell side was
severely fouled. Since the refinery regularly water washes the
tube side of the exchangers to
dissolve and remove ammonium
chloride
salts,
the
cleanliness of the tube side was
expected. The shell-side deposits consisted primarily of
hydrocarbon-based
materials
coupled with lesser quantities
of iron sulphide.
Table 1 shows the results for
the deposits obtained during the
root cause investigation. The
tube side was quite clean and
the small amount of material
obtained was found to be primarily iron sulphide and iron oxide
— corrosion by-products that
can form due to the reaction of
ammonium chloride salts with
the heat exchanger tubes. The
shell-side deposits were mostly
organic but were coupled with
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NHT deposit analyses
All results in wt%
Tube deposit
Shell deposit
Carbon
<1
57
Hydrogen
Nil
5
Nitrogen
Nil
4
Oxygen
10
13
Sodium
Nil
3
Sulphur
22
11
Chlorine
Nil
1
Iron
63
4
Silicon
1
Trace
Composition Primarily
Primarily
inorganic
organic
Table 1
some iron compounds and chloride salts. The organic portion
contained substantial amounts
of carbon; the hydrogen-tocarbon atomic ratio revealed
that the deposit was composed
of degraded, partially cyclised
polymeric material. There was
also a significant amount of
nitrogen found in the shell-side
deposits. Nitrogen is commonly
found in deposits from coker
naphtha due to the presence of
amines and pyrroles, which can
take part in polymer formation.
Feedstock analyses
Analyses of HDS unit feed
streams provide insight into the
fouling mechanism root cause.
Tests that are utilised to identify
potential contributors to fouling
are shown in Table 2. Several
of the analyses look for
components that can take part
in various polymerisation reactions, while other tests identify
inorganic constituents such as
iron sulphide that contribute to
deposit formation.2
Samples of the NHT feed
components were analysed to
identify
possible
fouling
precursors.
The
analyses
summarised in Table 3 revealed
that the purchased naphtha
was relatively free of fouling
precursors. Additionally, the
handling practices of the
purchased naphtha had not
changed from prior cycles
when minimal fouling was
observed. After this review of
the purchased naphtha, it was
eliminated as a root cause.
The combined crude and
coker
naphthas
contained
components that lead to polymer formation. Olefins, as
measured by the bromine
number, and mercaptans are
both significant fouling contributors. When these components
are present in the feed stream,
they will produce free radical
polymers. Elevated basic nitrogen was also detected in the
feed. Basic nitrogen in combination with organic acids
participates in condensation
polymerisation.2 The organic
acid content was below the
detection limit, so it is unlikely
Typical HDS feed analyses
Analytical test
Bromine number, g Br/100 g
Mercaptan sulphur, ppmw as S
Hydrogen sulphide, ppmw as S
Total acid number, mg KOH/g
Basic nitrogen, ppmw as N
Pyrrole-indole nitrogen, ppmw N
Metals, ppm
Filterable solids, ppm
Fouling concerns
Olefins
Free radical polymerisation
Iron sulphide formation
Condensation polymerisation
Condensation polymerisation
Polymerisation
Inorganic deposits
Inorganic deposits
Table 2
PTQ Q4 2012 3
NHT feed analyses
Analytical test
Purchased naphtha
Filterable solids, ppmw
<10
API Gravity
58.3
Bromine number, g Br/100 g
1.4
% Saturated H, normalised
94.5
% Olefinic H, normalised
0.2
% Aromatic H, normalised
5.3
Mercaptan sulphur, ppmw as S
13
H2S, ppmw as S
<1
Total acid number, mg KOH/g
<0.05
Basic nitrogen, ppmw as N
<10
Pyrrole-Indole nitrogen, ppmw as N
0.2
Combined crude and coker naphtha
<10
60.9
14
96.2
1.4
2.4
308
10
<0.05
23.6
3.7
Table 3
Gum test results with combined naphtha
Sample
Test
Combined naphtha Existent gums
Combined naphtha
Stressed
Polymer Inhibitor A
Stressed
Polymer Inhibitor B
Stressed
Combined naphtha
Stressed
Polymer Inhibitor A
Stressed
Polymer Inhibitor B
Stressed
Stress
Stress
medium temperature, ˚F (˚C)
N/A
N/A
Nitrogen
212 (100)
Nitrogen
212 (100)
Nitrogen
212 (100)
Air
212 (100)
Air
212 (100)
Air
212 (100)
Results,
Reduction
mg/100 ml
%
11
N/A
35
11
69
16
54
48
15
69
23
52
Table 4
that these nitrogen-based reactions were the primary cause of
the high fouling rate.
Laboratory fouling tests
Fouling simulation studies are
used to generate deposits and
study the ability of chemical
additives to control their formation. For these feed streams,
existent gums3 were used to
measure the as-received polymer content, and thermally
stressed gums were used to
determine the tendency to
produce additional polymer.
The thermal stress test is also
used to select the best-performing polymer inhibitor. Table 4
shows a summary of the gum
tests run on the feeds to this
NHT unit.
Dispersion tests are used to
measure the ability of dispersant
additives to hold deposits in
4 PTQ Q4 2012
solution. Samples of the gum
deposits from the stress tests or
deposits from the heat exchangers are mixed with a clear
organic solvent along with various dispersant additives. The
mixtures are shaken and then
allowed to settle. An effective
dispersant will hold the deposit
in solution longer than an
untreated sample. Dispersion
tests were run on the polymeric
material formed from the gum
tests in order to identify an effective product for controlling
deposition of the foulant material. A dispersant specifically
formulated for control of organic
deposits was found to be highly
effective for this application.
Treatment programme
implementation
Based on the root cause analysis, a Baker Hughes Lifespan
treatment
programme
was
implemented to control polymerisation of the reactive feeds
and to disperse the organic and
inorganic particulates. Polymer
Inhibitor A was used to treat
the coker naphtha stream before
it was mixed with the straightrun naphtha. A dispersant was
injected at the NHT charge
pump to provide good mixing
for treatment of the combined
feed
stream,
including
purchased naphtha. This combination programme has provided
excellent
fouling
inhibition
capability in similar units and
offers the advantage of being
able to adjust the treat rates of
the two components as needed.
Unit monitoring tools and
trends
In order to verify the performance of the chemical treatment
programme, a heat exchanger
monitoring programme was
utilised to compare current
operation
to
prior
cycle
performance. The heat transfer
coefficient for the feed-effluent
heat exchanger bank was
trended versus run time. Figure
3 shows the rate of decline of
the exchanger heat transfer
coefficient for the last three
cycles. The first two cycles
shown are prior to chemical
treatment, while the last cycle
shown is after implementation
of the chemical treatment
programme. During the previous two untreated cycles, the
heat transfer capabilities for the
preheat exchangers declined at
a rate of 0.11 U-coefficient units
per day, resulting in a 202-day
run and 0.06 U-coefficient units
per day for a 404-day run. For
the recent cycle with the treatment programme in place, the
heat transfer decline was 0.01
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80
Cycle 1 − untreated
Cycle 2 − untreated
Cycle 3 − treated
75
U, BTU/hr / SF / ºF
U-coefficient units per day,
resulting in a 662-day run. The
treatment programme allowed
the refinery to operate the NHT
uninterrupted
until
the
normally scheduled turnaround
for catalyst replacement.
Figure 4 compares one of the
heat exchanger tube bundles
with and without the antifoulant treatment programme.
Both photographs are taken at
the end of run prior to cleaning. The bundle appearance
and deposits from cycle 2 were
consistent with degraded polymers
coupled
with
iron
sulphide. Clearly, there was
significantly less deposit with
the fouling control treatment
programme in place.
70
65
60
55
50
45
40
35
30
0
100
200
300
400
500
600
700
Days
Figure 3 Heat transfer coefficient trends
After cycle 2
After cycle 3
11 months online (untreated)
21 months online (treated)
Conclusion
The root cause of the increased
heat exchanger fouling rate was
the shift in the NHT feed quality. The refinery configuration
change implemented just prior
to the increased heat exchanger
fouling altered the NHT feed to
include C4. The coker butanes
and butylenes contain a high
concentration of mercaptans
and olefins, which lead to free
radical polymerisation.
Identification of the primary
cause of fouling enabled the
development of an antifoulant
additive treatment programme
that was able to control the rate
of heat exchanger fouling. This
programme provided the refinery an economic return of over
500% by permitting the unit to
run at full throughput rates,
preventing unit shutdowns
prior to scheduled catalyst
replacements and reducing
maintenance costs.
LIFESPAN is a trademark of Baker
Hughes.
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Figure 4 Heat exchanger tube bundle prior to cleaning
Acknowledgements
The authors wish to extend their
gratitude to Tomasa Ledesma, Baker
Hughes Antifoulant Chemist, for her
work in conducting the fouling studies;
the analytical group at the Baker Hughes
Sugar Land laboratory; and Ralph Kajdasz,
Baker Hughes Account Manager, for his
efforts in keeping the programme running
at the refinery, and for development and
calculation of the monitoring data.
References
1 Wright B E, The causes and control of
fouling in hydrodesulphurization units
— a tutorial, AIChE 2002 Spring National
Meeting, 3rd International Symposium on
Mechanisms and Mitigation of Fouling in
Refining and Upgrading, Mar 2002.
2 Medine G, Wright B E, Distillate
hydrotreater fouling, AIChE 2008 Spring
National Meeting, Apr 2008.
3 ASTM D 381, Standard Test Method for
Gum Content in Fuels by Jet Evaporation.
Bruce Wright is a Senior Technical
Support Engineer in Baker Hughes’s
Industrial Technology department in
Sugar Land, Texas, specialising in the
hydrocarbon process industries. He
holds a BS in chemical engineering from
Rensselaer Polytechnic Institute, Troy,
New York, a MBA from the University of
Houston, and is a registered professional
engineer in the State of Texas.
Todd Hochheiser is a Refinery
Optimization Manager with Valero
Energy Corporation. He holds a BS
degree in chemical engineering from the
University of Delaware, an MBA from the
University of California, and is a member
of the American Institute of Chemical
Engineers.
PTQ Q4 2012
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