This document discusses corrosion under insulation (CUI), which occurs in the space between insulating material and metal surfaces in various industries like oil & gas, chemicals, and food processing. CUI is caused by water collecting in this space from sources like rain, leaks, or condensation. It can lead to localized corrosion and wall loss. The document examines major factors that influence CUI like temperature, insulation design, and environmental conditions. It also identifies specific units and areas that are susceptible to CUI, such as pipes near cooling towers or steam vents. The appearance of CUI and methods to prevent it through coatings and insulation practices are described. Inspection and monitoring techniques for CUI are also discussed, including a probe array sensor

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CORROSION
Corrosion taking place under
insulating materials
Introduction
The corrosion that takes place under
insulation material is a major problem.
It has been a primary problem in the oil &
gas, chemical, food processing, and other
industries for many years and has cost
many millions of dollars in inspection and
repair of process pipes and pipelines.
The American Petroleum Institute code,
API 570 Inspection, Repair Alteration
and Re-rating of In-service Piping Systems,
(June 1993), identifies Corrosion Under
Insulation (CUI) as a special concern.
In 2003, the European Corrosion Federation
reported that most leaks in the refining
and chemical industries were due to CUI,
rather than process leaks. When insulation
material becomes wet (because of poor
installation practices, subsequent abuse or
failure to specify good vapor barriers and
waterproofing materials), it “creates the
potential for corrosive failure of the piping”.
Whether pipes are above ground or buried,
proper design and installation techniques
can control corrosion. CUI is one of the
predominant mechanical integrity issues
affecting the ethylene industry. Occurrence
can be erratic and sometimes undetectable
based on visual examination. In addition
to these recognized problem areas, it is
also important to look for areas that are
susceptible to CUI due to swing conditions
or non-flow areas, even though the design
and observed operating condition of the
line fall outside this range.
It results from the collection of water in the
vapor space (or annulus space) between
the insulation and the metal surface.
Sources of water may include rain, water
leaks, condensation, cooling water tower
drift, deluge systems, and steam tracing
leaks. CUI causes wall loss in the form of
localized corrosion. Plants located in areas
with high annual rainfall or warm, marine
locations are more prone to CUI than plants
located in cooler, drier, mid-continent
locations. Units which are located near
cooling towers and steam vents are highly
susceptible to CUI, as are units whose
operating temperature cycle through the
dew point on a regular basis. The external
inspection of insulated systems should
include a review of the integrity of the
insulation system for conditions that could
lead to CUI and for signs of ongoing
CUI, i.e. rust stains or bulging.
Prevention of CUI can be carried out
through proper coating and good
insulation practices. Good installation
and maintenance of insulation prevents
ingress of large quantities of water.
A coating system is frequently specified
for component operating in the CUI
temperature range, and where CUI has
been a problem. A good coating system
should last a minimum of fifteen years.
Currently there are few reliable inspection
and monitoring techniques and so
new sensors for CUI inspection.
Major factors which affect CUI
• It affects externally insulated piping
and equipment and those that are
in intermittent service or operate
between –12°C to 175°C for carbon
Fig.1. An insulated pipeline, which faced corrosion in a petrochemical plant.
CUI takes place under insulating material in the oil & gas, chemical, and food processing industries,
to name but a few industries affected, costs millions of dollars on a yearly basis. In this article,
the major factors that lead to corrosion under insulation are examined and the major types of
units and equipment that get affected are discussed. CUI appearance is also discussed. Further,
an important section of the article looks at how corrosion under insulating materials can be
prevented, as well as preventive inspection and monitoring practices, including the use of a
probe array sensor inserted to detect its formation at thermally insulated pipeline field joints.
By Dr. Arwind Kumar Dubey, Senior Integrity Engineer, Intertek, Dubai, United Arab Emirates

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CORROSION
and low alloy steels whereas 60°C
to 205°C for austenitic stainless
steels and duplex stainless steels.
• Corrosion rates increase with
increasing metal temperature up to
the point where the water evaporates
quickly. For insulated components,
corrosion becomes more severe at
metal temperatures between the
boiling point 100°C and 121°C,
where water is less likely to vaporize
and insulation stays wet longer.
• Design of insulation system,
insulation type, temperature and
environment are critical factors.
• Poor design and/or installations
that allow water to become trapped
will increase CUI.
• Insulating materials that hold moisture
(wick) can be more of a problem.
• Cyclic thermal operation or
intermittent service can increase
corrosion.
• Equipment that operates below the
water dew point tends to condense
water on the metal surface thus
providing a wet environment and
increasing the risk of corrosion.
• Damage is aggravated by
contaminants that may be leached
out of the insulation, such as
chlorides.
• Plants located in areas with high
annual rainfall or warmer, marine
locations are more prone to CUI
than plants located in cooler, drier,
mid-continent locations.
• Environments that provide airborne
contaminants such as chlorides
(marine environments, cooling tower
drift) or SO2 (stack emissions) can
accelerate corrosion.
Units or equipment which get
affected by CUI
• Insulated equipment and piping are
susceptible to CUI under conditions
noted above even on piping and
equipment where the insulation
system appears to be in good
condition and no visual signs
of corrosion are present.
• CUI can be found on equipment with
damaged insulation, vapor barriers,
weather proofing or mastic, or
protrusions through the insulation
or at insulation termination points
such as flanges.
• Equipment designed with insulation
support rings welded directly to the
vessel wall (no standoff); particularly
around ladder and platform clips,
and lifting lugs, nozzles and stiffener
rings.
• Piping or equipment with
damaged/leaking steam tracing.
• Localized damage at paint and/or
coating systems.
• Locations where moisture/water
will naturally collect (gravity drainage)
before evaporating (insulation support
rings on vertical equipment) and
improperly terminated fireproofing.
• Vibrating piping systems that have
a tendency to inflict damage to
insulation jacketing providing a
path for water ingress.
• Deadlegs
• Steam tracer tubing penetrations.
• Caulking that has hardened, has
separated, or is missing.
• Bulges or staining of the insulation
or jacketing system or missing
bands.
• Low points in piping systems that
have a known breach in the insulation
system, including low points in long
unsupported piping runs.
• Carbon or low-alloy steel flanges,
bolting, and other components
under insulation in high-alloy piping
systems.
• Locations where insulation plugs
have been removed to permit
piping thickness measurements
on insulated piping and equipment
should receive particular attention.
CUI appearance
• Carbon and low alloy steels
are subject to localized pitting
corrosion and or localized loss
in thickness.
• 300 Series SS are also subject to
Stress Corrosion Cracking (SCC)
if chlorides are present, while the
duplex SS are less susceptible.
• 300 Series SS and duplex SS are
subject to pitting and localized
corrosion. For 300 Series SS,
specifically in older calcium silicate
insulation (known to contain
chlorides), localized pitting and
chloride stress corrosion cracking
can occur.
• After insulation is removed from
carbon and low alloy steels, CUI
damage often appears as loose,
flaky scale covering the corroded
component. Damage may be highly
localized.
• In some localized cases, the
corrosion can appear to be
carbuncle type pitting (usually
found under a failed paint/coating
system).
Fig. 2A & 2B show the appearance of CUI after the removal of insulating material in a
petrochemical plant.
(A)
(B)

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CORROSION
Control of CUI
• Majority of construction materials
used in plants are susceptible to
CUI degradation, mitigation is best
achieved by using appropriate
paints/coatings and maintaining
the insulation/sealing/vapor barriers
to prevent moisture ingress.
• Flame-sprayed aluminum coatings
have been used on carbon steels.
The coating corrodes preferentially
by galvanic action, thereby
protecting the base metal.
• High quality non-metallic coatings,
properly applied to the surfaces to
be insulated can provide long term
protection.
• Thin aluminum foil wrapped on
stainless steel piping and equipment
has been used on stainless steels as
an effective barrier under insulation.
• Careful selection of insulating
materials is important. Closed-cell
foam glass materials will hold less
water against the vessel/pipe wall
than mineral wool and potentially
be less corrosive.
• Low chloride insulation should be
used on 300 Series SS to minimize
the potential for pitting and
chloride SCC.
• It is not usually possible to modify
operating conditions. However,
consideration should be given
to removing the insulation on
equipment where heat conservation
is not as important.
CUI inspection and monitoring
• An inspection plan for corrosion under
insulation should be a structured and
systematic approach starting with
prediction/analysis, then looking at
the more invasive procedures. The
inspection plan should consider
operating temperature; type and
age/condition of coating; and type
and age/condition of insulation
material. Additional prioritization
can be added from a physical
inspection of the equipment, looking
for evidence of insulation, mastic
and/or sealant damage, signs of
water penetration and rust in gravity
drain areas around the equipment.
• Although external insulation may
appear to be in good condition, CUI
damage may still be occurring. CUI
inspection may require removal of
some or all insulation. If external
coverings are in good condition
and there is no reason to suspect
damage behind them, it may not
be necessary to remove them
for inspection of the vessel.
• Considerations for insulation removal
include history of CUI for the vessel
or comparable equipment, visual
condition of the external covering
and insulation, evidence of fluid
leakage, e.g. stains, equipment in
intermittent service, condition/age
of the external coating.
• Common areas of concern in process
units are high moisture areas such
as those down-winds from cooling
towers, near steam vents, deluge
systems, acid vapors, or near
supplemental cooling with water
spray.
Inserted probe array sensor
for CUI monitoring
The Inserted Probe Array Sensor acts as a
‘corrosion fuse’ detector that will provide
an indication of corrosion occurring at the
pipe surface, at known discrete locations.
It was originally designed to be installed
during the remediation and mitigation
of corrosion damage under thermally
insulated pipeline field joints. There are
two common types of pipeline insulation
repair processes. The first requires the
old cladding to be removed with the
insulation left in place. Insulation tape
is wrapped around the affected area and
a new protective cladding is strapped
in place. The second involves removing
an entire section of insulation from a
damaged area. The pipe is repaired and
cleaned, and new insulation is installed.
Insulating tape is then applied and a
protective outer cladding is strapped
in place.
References
1. API 571-Damage Mechanisms
Affecting Fixed Equipment in
the Refining Industry.
2. Risk-Based Inspection Technology,
API Recommended Practice 581.
Fig. 3. A corrosion fuse inserted probe array sensor for CUI monitoring.
About the author
Dr. Arwind Kumar Dubey holds a Ph.D. degree in
Corrosion Chemistry from the University of Delhi, Delhi,
India and an MBA degree from an Indian University. He
is certified by NACE as a Senior Corrosion Technologist
and Coating Inspector Professional. Dr. Dubey has ten
years’ work experience in R&D, oil/gas, refinery and
petrochemicals engineering. His expertise is related
to chemical treatment, coatings, material selection,
corrosion protection, RBI (Risk Based Inspection),
Meridium. He has worked in India, Oman, Saudi
Arabia, and the United Arab Emirates. He has published many corrosion related
research papers in international journals and is, furthermore, a reviewer of a
number of chemical engineering journals e.g. the Polish Journal of Chemical
Technology, Corrosion, the Indian Journal of Chemical Technology. Dr. Dubey
is an individual member of NACE and is a Professional Member of the Institute
of Corrosion (MICorr).