Chemical Engineering May 2015 - 78

D
FIGURE 6. Troubleshooting algorithm for internal corrosion
No
Internal corrosion is mainly influenced by the chemical
composition of the process fluid. Do you have sulfur
compounds present in your process fluid composition?
Yes
No
Do you experience localized or general tube-wall thinning?
Yes
End troubleshooting
procedure.
DE
Yes
Its possible that the inlet process fluid contains particulate
matter. Particulate matter can increase the corrosion rate by
stripping away protective scale and exposing the fresh metal
to continuous corrosion process (see Ref. 1). Inspect upstream
process equipment and resolve any deficiency that can cause
particulate formation in process stream.
Is your problem solved?
Yes
Sulfidic corrosion may have happened inside the tube walls,
beware of chemical components like chlorides and hydrogen
that can aggravate the corrosion rate. Also local flame
impingement and high skin temperatures can increase the
corrosion rate.
Control the chemical composition of the process fluid and
lower critical species concentration. In case of frequent flame
impingements, solve the problem according to instructions
given in burner troubleshooting guide (Ref. 2).
Is your problem solved?
No
Do you have naphthenic acids present in
your process fluid composition?
Yes
Do you experience tube wall thinning in turbulent areas, such as bends
or pass outlets?
Yes
No
Naphthenic acid corrosion may have occurred inside the tube walls.
Beware that high skin temperatures can increase the corrosion rate.
Control the chemical composition of
process the fluid and lower critical species
concentration if possible.
Is your problem solved?
Key:
A
Hotspot
B
Internal fouling
C
External fouling
D
Internal corrosion
Yes
Go to Point
DE
No
No
Yes
Did you experience high corrosion defects after a recent
overhaul or upstream equipment malfunction? Mostly de-salter
malfunction or low performance?
No
Seek engineering
consultancy.
No
Go to Point
DE
Yes
Two-phase flow currents with high linear
velocity in either of the phases, or slug
flow regimes can cause local or overall
corrosion and even enhance the corrosion
rate caused by other factors. Consult an
expert engineering team and try to figure out
possible improper flow regimes in boiling
regions of tubes. Is your problem solved?
Yes
Is your fired heater in atmospheric or vacuum towers charge
heating service?
No
No
flowrate, this can lead to severe internal
fouling. Operators should be
warned about the possibility of this
problem, specifically after overhaul
or upstream equipment malfunction
and maintenance.
As the next step, the nature of
the process should be noted. For
visbreakers or any service in which
76
heavy feed is vaporizing, coke
buildup is a likely possibility. As coke
formation in these kinds of heaters
is highly anticipated, controlling operating
conditions, especially the
items mentioned in previous steps of
this algorithm, is very important and
vital. By following the right steps,
operators may control - and even
in some cases eliminate - coke
buildup phenomena.
Other steps of this algorithm are
dedicated to the decoking and spalling
practices that should be followed,
depending on the nature of
the internal fouling problem.
Following this procedure would
usually eliminate and even prevent
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