Classification: Internal Use
Key Changes in
rd
API 571, 3 Edition
July 2020 - Part 1
Baher Elsheikh
Classification: Internal Use
Three Damage Mechanism Withdrawn
Three Damage
Mechanism
withdrawn and
two of them
combined with
other damage
Mechanisms as
listed below,
Steam blanketing (DM#26), withdrawn and combined
with DM#30 “Short-term Overheating-Stress Rupture
(Including Steam Blanketing)”
DM# number is as
referenced form
Table 4.1 “Key to
damage
mechanism”
Sulfate Stress Corrosion Cracking (DM#61) withdrawn
and not present on API 571-2020
Vibration induced fatigue (DM#56) withdrawn and
combined with DM#54“Mechanical Fatigue (Including
Vibration-induced Fatigue)”
API RP 571 2020
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
Four Damage Mechanism Added
DM# 67: Brine Corrosion
DM# 68: Concentration Cell Corrosion
DM# 69: Hydrofluoric Acid Stress Corrosion of Nickle Alloys
DM# 70: Oxygenated Water Corrosion (Non-boiler)
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
Main Changes in API RP 571 3rd
• Became ANSI APPROVED
• Structure of the RP changed by removing the subcategories of the damage
mechanisms
The old categories in 2nd edition:
4.2 Mechanical and Metallurgical Failure Mechanism,
4.3 Uniform or Localized Loss of Thickness,
4.4 High Temperature Corrosion,
4.5 Environment – Assisted Cracking,
Section 5 Refining Industry
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
Changes in API 571 3rd Edition - 2020
Order of the damage mechanisms changed; in 2011 edition was ordered by relative damage
mechanisms while in 2020 ordered in alphabetic sequence
New Annex (Annex A) added listed useful standards and References relevant to API RP 571
In addition the following previous 5 categories DM as per 2011 edition now removed
a) General and local metal loss due to corrosion and/or erosion
b) Surface connected cracking
c) Subsurface cracking
d) Microfissuring /microvoid formation
e) Metallurgical changes
API RP 571 2020
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
API 571, 2020
Changes in API 571 3rd Edition - 2020
The 2020 RP edition is more
specific in metallurgical terms
Replace the “heat treatment”
expression with the intended
type of heat treatment
(tempering, annealing,…)
Use specific terms of the
intended metallic phases (like
alpha prime).
There are several changes where
point relocated between different
paragraphs like moving from
inspection and monitoring to
prevention and mitigation as it is
better repressing the meaning of
intention of the statement
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
The equivalent values
between the US and SI
units are changed in
2020 edition as it was
direct conversion in
2011 edition
while in 2020, the value
in SI units is edited to
reflect the nearest inter
value.
API 571, 2020
Changes in API 571 3rd Edition - 2020
In addition there’s
some case where the
value in SI unit where
mistakenly written and
now corrected in 2020
edition
Example: In 2020
edition, atmospheric
corrosion increases
with temperature
250 °F (120 °C) while
in 2011 edition it was
250 °F (121 °C).
TRAINING COURSE
Example: the
recommended heat
treatment to prevent
alkaline carbonate
stress corrosion
cracking in 2020 edition
is 1200F to 1225°F
(650°C to 665°C) while
in 2011 edition it was
1200°F to 1225°F
(649°C to 663°C)
Example for conversions
correction: in 2020 edition,
the susceptible range of
temperature for 885°F
embrittlement is 600 °F to
1000 °F (370 °C to 540 °C)
while in 2011 edition 700°F
to 1000°F (371°C to 538°C)
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
Changes in API 571 3rd Edition - 2020
Flow accelerated corrosion (FAC) Term appeared in 2020 edition under the DM ‘Boiler
water and steam condensate corrosion
Many studies and publications from EPRI studies earlier the FAC and how it is differ
from normal erosion corrosion DM but that was not covered in API 571 up to 2011
edition
FAC may be defined as metal loss that occurs in carbon steel equipment when the
normally protective magnetite (Fe3O4) layer is dissolved into a flowing stream of
water or water and steam. The metal goes through continuous cycling of oxide layer
production followed by loosening and dissolution into the turbulent stream. The
oxide layer is not able to protect the metal, and the continuous loss of the oxide layer
results in the steady loss of metal thickness.
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
Changes in API 571 3rd Edition - 2020
2020
Four Conditions Required for FAC to be Active
Water Chemistry
Hydrodynamics
Materials
Temperature
the water in the
system needs to
be demineralized
with a pH of less
than 9.6
Turbulent flow is
required
low concentrations
of Chromium,
Molybdenum, and
Copper
water temperature
to be between
212F and 572°F
(100 -300 ° C)
API 571, 2020
TRAINING COURSE
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 C) Embrittlement
Changed Para.
2020 Edition
Damage Description
changed as
indicated
885 °F (475 °C) embrittlement
is a loss of ductility and
fracture toughness due to a
metallurgical change that can
occur in stainless steels
containing a ferrite phase as
the result of exposure in the
temperature range 600 °F to
2011 Edition
885°F (475°C) embrittlement is
a loss in toughness due to a
metallurgical change that can
occur in alloys containing a
ferrite phase, as a result of
exposure in the temperature
range 600°F to1000°F (316°C to
540°C).
1000 °F (315 °C to 540 °C). The
embrittlement can lead to
cracking failure.
API 571, 2020
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Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
Affected Materials:
Austenitic stainless
added to the
affected materials
2011 Edition
a) 400 series SS (e.g. 405, 409,
410, 410S, 430, and 446).
a) 400 Series SS (e.g., 405, 409,
410, 410S, 430 and 446).
b) Duplex stainless steels such
as Alloys 2205, 2304, and 2507.
b) Duplex stainless steels such
as Alloys 2205, 2304 and 2507.
c) Austenitic (300 series)
stainless steel weld metals,
which normally contain up to
about 10 % ferrite phase to
prevent hot cracking during
welding.
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
Critical Factors
Additional critical
factors added
The lower-chromium alloys (e.g. 405, 409, 410, and 410S) are less susceptible to
embrittlement. The higher Cr ferritic stainless steels [e.g. 430 (16 % to 18 % Cr)
and 446 (23 % to 27 % Cr)] and duplex stainless steels (22 % to 25 % Cr) are much
more susceptible.
Although it has not yet been shown in all 300 series SS weld metals, Charpy
impact testing of Type 308 and Type 347H SS weld metal aged in approximately
the 850 °F to 885 °F (455 °C to 475 °C)
temperature range has found evidence of 885 °F (475 °C) embrittlement, with
individual sample results in some cases being less than 15 ft-lb (20 J) at ambient
temperatures. However, 885 °F (475 °C) embrittlement of austenitic stainless steel
weld metal historically has not been found to be a significant concern in typical
refining applications.
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
Critical factors:
Paragraph of the
effect of the ferrite
phase changed to be
considered for DSS
Additional
requirements to
cool DSS rapidly
after welding to
avoid embrittlement
phases
API 571, 2020
a) Increasing amounts of ferrite
phase in duplex stainless steels
increase susceptibility to
damage when operating in the
high-temperature range of
concern. A dramatic increase in
the ductile-to-brittle transition
temperature will occur.
2011 Edition
a) Increasing amounts of ferrite
phase increase susceptibility to
damage when operating in the
high temperature range of
concern. A dramatic increase in
the ductile-to-brittle transition
temperature will occur.
Duplex stainless steels also
need to be cooled rapidly after
welding to avoid formation of
embrittling phases..
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
2011 Edition
Critical factors:
Paragraph edited as
shown with
indication that
metallic phase at
the high
temperature is
alpha prime phase
API 571, 2020
Damage is cumulative and
results from the formation of
an embrittling ordered metallic
phase (alpha prime phase) that
occurs most readily at
approximately 885 °F (475 °C)
Damage is cumulative and
results from the precipitation
of an embrittling intermetallic
phase that occurs most readily
at approximately 885°F
(475°C).
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
Inspection and
monitoring
Some restrictions
and precautions
added about the
application of
hardness as a
detection method
for the
embrittlement as
indicated
API 571, 2020
Field hardness testing may
distinguish embrittled from
non-embrittled material, but
hardness testing alone is
generally not definitive. Also,
the hardness test itself may
produce cracking, depending
on the degree of
embrittlement.
2011 Edition
An increase in hardness is
another method of evaluating
885°F embrittlement
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# 885 F (475 c) Embrittlement
Changed Para.
2020 Edition
Inspection and
monitoring
Hammer test added
as field detection
technique with
restriction on the
application as it
might crack the
component
API 571, 2020
Hammer testing (“field impact testing”) is considered a
destructive test. Tapping a suspect component with a hammer
may crack the component, depending on the degree of
embrittlement. Hammer testing might confirm that a component
is not badly embrittled, if it does not crack, or that it is
embrittled, if it does crack.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Corrosion
Changed Para.
2020 Edition
Inspection and
Monitoring
Additional
inspection target
locations added as
indicated
API 571, 2020
Visual inspection (VT) of internal surfaces at flow impingement
areas, turbulent flow areas, liquid/vapor interfaces, and of
welds/heat-affected zones (HAZs) is effective in identifying
localized corrosion.
Sometimes a pit gauge is used in conjunction with visual
examination to provide specific data on extent of metal loss.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Corrosion
Changed Para.
2020 Edition
2011 Edition
Critical Factors
Concentration of
Amine replaced by
Amine type
While a separate
point added
indicating that
concentration does
not appear to have
significant impact on
propensity
API 571, 2020
The critical factors are the level
of tensile stress, the type of
amine, and temperature.
The critical factors are the level
of tensile stress, amine
concentration and
temperature
g) Amine concentration does
not appear to have a significant
effect on the propensity for
cracking.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Corrosion
Changed Para.
2020 Edition
Critical Factors
New point added
about the effect of
temperature in
increasing g the
susceptibility to
cracking
Increasing temperature increases the likelihood and severity of cracking;
however, cracking has been reported down to ambient temperatures with
some amines, MEA in particular. Other than in special cases (such as where the
steel component is completely clad or overlayed with stainless steel or other
alloy and the welds are not exposed), PWHT is now commonly recommended
for all lean amine systems (excluding fresh amine) at all operating
temperatures, regardless of amine type.
Some refiners also PWHT’d rich amine service equipment, whether for amine
SCC resistance, wet H2S [SSC and stress-oriented hydrogen-induced cracking
(SOHIC)] resistance, or both. Refer to API 945 for guidelines on PWHT for
various amine services
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Corrosion
Changed Para.
2020 Edition
Inspection and
Monitoring
One point removed
from 2011 edition
and new point
added to 2020
edition as indicted
API 571, 2020
The level of amine degradation
products (e.g. bicine, oxalate,
and formate salts), should be
monitored. An increase in iron
content of the amine solution
will coincide with an increase
in the level of these
degradation products.
2011 Edition
Monitoring should target the
hot areas of the unit such as
the reboiler feed and return
line, the hot lean/rich amine
piping, and the stripper
overhead condenser piping.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Corrosion
Changed Para.
2020 Edition
Inspection and
Monitoring
Additional
inspection target
locations added as
indicated
Visual inspection (VT) of internal
surfaces at flow impingement areas,
turbulent flow areas, liquid/vapor
interfaces, and of welds/heataffected zones (HAZs) is effective in
identifying localized corrosion.
Sometimes
a pit gauge is used in conjunction
with visual examination to provide
specific data on extent of metal loss.
2011 Edition
Visual examination and UT
thickness measurement are
the methods used for internal
equipment inspection. UT
scans or profile radiography
are used for external
inspection.
Note: Profile Radiography and UT
already considered in 2011 but under
separate points
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Stress Corrosion Cracking
Changed Para.
2020 Edition
Critical Factors
Concentration of
Amine replaced by
Amine type
While a separate
point added
indicating that
concentration does
not appear to have
significant impact on
propensity
API 571, 2020
The critical factors are the level
of tensile stress, the type of
amine, and temperature.
2011 Edition
The critical factors are the level
of tensile stress, amine
concentration and
temperature
g) Amine concentration does
not appear to have a significant
effect on the propensity for
cracking.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Stress Corrosion Cracking
Changed Para.
2020 Edition
Critical Factors
New point added
about the effect of
temperature in
increasing g the
susceptibility to
cracking
Increasing temperature increases the likelihood and severity of cracking;
however, cracking has been reported down to ambient temperatures with
some amines, MEA in particular. Other than in special cases (such as where the
steel component is completely clad or overlayed with stainless steel or other
alloy and the welds are not exposed), PWHT is now commonly recommended
for all lean amine systems (excluding fresh amine) at all operating
temperatures, regardless of amine type.
Some refiners also PWHT’d rich amine service equipment, whether for amine
SCC resistance, wet H2S [SSC and stress-oriented hydrogen-induced
cracking (SOHIC)] resistance, or both. Refer to API 945 for guidelines on PWHT
for various amine services
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Stress Corrosion Cracking
Changed Para.
Prevention and
Mitigation
Reference made to
NACE SP0472 for the
stress relief
requirements
2020 Edition
2011 Edition
Carbon steel welds in piping and
equipment should be stress relieved
in accordance with API 945 and
NACE SP0472. The recommended
minimum stress-relief temperature
is 1175 ± 25 °F (635 ± 15 °C). The
same recommendation applies to
repair welds and to internal and
external attachment welds.
PWHT all carbon steel welds in
piping and equipment in
accordance with API RP 945.
The same requirement applies
to repair welds and to internal
and external attachment welds
For local PWHT, recommended heat
treatment band width is listed in
NACE SP0472 with reference to WRC
452.
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Stress Corrosion Cracking
Changed Para.
Prevention and
Mitigation
Specific
recommendations
for upgradation to
alloy 400 replaced
by stainless steel
API 571, 2020
2020 Edition
2011 Edition
Consider using solid or clad
stainless steel or other
corrosion-resistant alloys in
lieu of carbon steel
Use solid or clad stainless steel,
Alloy 400 or other corrosion
resistant alloys in lieu of
carbon steel.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Amine Stress Corrosion Cracking
Changed Para.
Inspection and
monitoring
2020 Edition
2011 Edition
c) Liquid penetrant testing (PT)
may be used but should not be
the only means of detection. PT
may not be effective in finding
tight cracks because the cracks
are oxide filled.
b) PT is usually not
effective in finding tight
and/or scale filled cracks
and should not be used.
d) RT may not be effective in
detecting fine, tight cracks.
API 571, 2020
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Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Affected Materials
2020 Edition
2011 Edition
a) Copper-zinc alloys (brasses,
especially as zinc increases
above 15 %), including
admiralty brass and aluminum
brasses, in environments with
aqueous ammonia and/or
ammonium compounds
a) Some copper alloys in
environments with aqueous
ammonia and/or ammonium
compounds.
b) Carbon steel in anhydrous
ammonia.
b) Carbon steel, especially highstrength steel, in anhydrous
ammonia
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Affected unit or
equipment
API 571, 2020
2020 Edition
2011 Edition
a)Copper-zinc alloy tubes in heat exchanger
1- Ammonia is present as a process
contaminant in some services or may be
intentionally added as an acid neutralizer.
2- Ammonia can be present in cooling
water.
3- Ammonia can be present in steam
condensate and boiler feedwater (BFW)
systems. Some chemicals used for treating
BFW, including hydrazine, neutralizing
amines, and ammonia-containing
compounds, can lead to SCC if not properly
controlled.
b) Non-stress-relieved carbon steel
ammonia storage tanks, piping, and
equipment in ammonia refrigeration units,
as well as some lube oil refining processes.
a) Copper-zinc alloy tubes in
heat exchangers.
b) Ammonia is present as a
process contaminant in some
services or may be
intentionally added as an
acid neutralizer.
c) Carbon steel is used for
ammonia storage tanks, piping
and equipment in ammonia
refrigeration units as well as
some lube oil refining
processes.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Prevention and
mitigation
2020 Edition
2011 Edition
Copper alloys
Copper alloys
2. The 90-10 Cu-Ni and 70-30 Cu-Ni
alloys have very low susceptibility.
Below 120 °F (50 °C), the cupronickels
are immune for all practical purposes
API 571, 2020
2. The 90-10CuNi and 7030CuNi alloys are nearly
immune.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Prevention and
mitigation
Restriction on the
hardness of the steel
removed from the
preventing factors
2020 Edition
2011 Edition
Nitrogen can be used to purge
oxygen prior to introduction of
ammonia into atmospheric and
pressurized storage systems.
Weld hardness should not
exceed 225 BHN.
Recommendations for
the use of Nitrogen
purge before
Ammonia introduction
to the vessel is added
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Inspection and
monitoring
Note added about the
application of the NDE
considering the
different orientation
of the cracks which
can be developed top
enhance the
detectability of the
cracks
API 571, 2020
2020 Edition
NOTE: NH3 SCC can occur parallel, transverse, or oblique to the
weld and HAZ. NDE applied should be performed to detect various
orientations of SCC
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Affected Materials
More affected
materials added as
shown
2020 Edition
2011 Edition
a) Carbon steel and low-alloy steels.
b) 300 series SS, duplex stainless steel, nickel-based
alloys, and titanium and its alloys are more resistant,
depending on ammonium bisulfide (NH4HS)
concentration and velocity.
1. Aluminum has been used for NH4HS corrosion
resistance in air coolers, but can suffer high corrosion
rates in high-velocity or turbulent locations.
2. Titanium and its alloys have been used for NH4HS
corrosion resistance in air coolers but can suffer
embrittlement from hydriding in these services.
a) Carbon steel is less
resistant.
b) 300 Series SS,
duplex SS, aluminum
alloys and nickel base
alloys are more
resistant, depending
on ammonium
bisulfide (NH4HS)
concentration and
velocity.
3.Welds in duplex stainless steel can be susceptible
to SSC.
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonia Stress Corrosion Cracking
Changed Para.
Inspection and
Monitoring
2020 Edition
d) Permanently mounted thickness monitoring sensors can be used.
e) Guided wave testing (GWT) can be used as a screening tool.
More affected
materials added as
shown
f) For steel (magnetic material) air cooler tubes (which are normally finned),
internal rotating inspection system (IRIS), magnetic flux leakage (MFL), near-field
testing (NFT), and other electromagnetic techniques can be used. ECT and IRIS can
be used to inspect nonmagnetic material air cooler tubes.
g) For steel (magnetic material) exchanger bundle tubes, IRIS, MFL, remote field
testing (RFT), and other electromagnetic techniques can be used. ECT and IRIS can
be used to inspect nonmagnetic material exchanger bundle tubes.
API 571, 2020
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonium Chloride and Amine Hydrochloride Corrosion
2011 Edition
Changed Para.
2020 Edition
Critical Factors
Water dew point value
removed and maxi.
temperature for
salting added to be
400F
API 571, 2020
Ammonium chloride salts may
precipitate from high-temperature
streams as they are cooled, depending
upon the concentration of NH3 and
HCl, and may corrode piping and
equipment at temperatures well above
the water dew point. Salting has been
observed up to approx. 400 °F (205 °C).
Ammonium chloride salts may
precipitate from high temperature
streams as they are cooled,
depending upon the
concentration of NH3 and HCl,
and may corrode piping and
equipment at temperatures well
above the water dewpoint [>
300°F (149°C)]
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Ammonium Chloride and Amine Hydrochloride Corrosion
2011
Changed
2020 Edition
RT or UT scanning methods [automated UT (AUT), manual
Para.
Edition
close-grid, scanning UT] can be used to determine remaining
Inspection and
Monitoring
Automated UT,
manual close grid and
scanning UT added as
preferred techniques
compared to spot UT
Additional point
added for online
monitoring using the
corrosion probes
API 571, 2020
wall thickness. These methods are preferred over typical spot
UT thickness monitoring because the corrosion is so highly
localized.
GWT can be used as a screening tool.
Corrosion probes or coupons can be useful, but the salt must
deposit on the corrosion probe element to detect corrosion
h) For steel (magnetic material) air cooler tubes (which are
normally finned), IRIS, MFL, NFT, and other electromagnetic
techniques can be used. ECT and IRIS can be used to inspect
nonmagnetic material air cooler tubes.
i) For steel (magnetic material) exchanger bundle tubes, IRIS,
MFL, RFT, and other electromagnetic techniques can be used.
ECT and IRIS can be used to inspect nonmagnetic material
exchanger bundle tubes.
RT or UT thickness
monitoring can be
used to determine
remaining wall
thickness.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Aqueous Organic Acid Corrosion
Changed Para.
Affected Materials
Note added to restrict
the use of austenitic
stainless steel unless it
is confirmed that
Halogens are not
present
API 571, 2020
2020 Edition
Most corrosion-resistant alloys
used in crude tower overhead
systems are generally not affected.
Austenitic stainless steels are
generally resistant, but this
mechanism is often associated with
streams that cause inorganic acid
corrosion as well as pitting and SCC
due to halogens (e.g. chlorides), so
their use should be avoided unless
it is known that halogens are not
present.
2011 Edition
b) Most other corrosion
resistant alloys used in crude
tower overhead systems are
generally not affected.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Aqueous Organic Acid Corrosion
Changed Para.
Affected units or
equipment
Additional affected
locations at mix
points and in
horizontal piping
added in 2020
edition
API 571, 2020
2020 Edition
b) Localized corrosion can occur at mix points from recovered oil
streams when wet streams combine with streams contaminated with
organic acid.
d) In horizontal piping, organic acid corrosion is generally found both
in the vapor space where liquid water can condense and along the
bottom of the piping where liquid water may run.
B A H E R E L S H E I K H – J U LY 2 0 2 0
Classification: Internal Use
DM# Boiler Water and Steam Condensate Corrosion
Changed Para.
2011
2020 Edition
Affected Factors
Edition
c) In the case of FAC, this protective oxide layer is
More illustration
dissolved or prevented from forming. Carbon steel
for the added term
is the most affected. Alloying elements in low-alloy
FAC is provided
steels such as Cr, Cu, and Mo can enhance
corrosion resistance. The most critical
temperature for FAC is 300 °F (150 °C), and it
decreases with increasing pH.
Too low an oxygen concentration increases the
corrosion due to the inability to form the
protective oxide layer. At least 3 ppb to 7 ppb may
be required to form the oxide layer.
API 571, 2020
e) Ammonia SCC
of Cu-Zn alloys can
occur due to
hydrazine,
neutralizing amines
or ammonia
containing
compounds..
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DM# Boiler Water and Steam Condensate Corrosion
Changed Para.
Critical Factors
2020 Edition
Oxygen Pitting
Concern added
e) Oxygen pitting can occur if the deaeration and oxygen
scavenging treatment are not working correctly.
API 571, 2020
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DM# Boiler Water and Steam Condensate Corrosion
Changed Para.
Affected Units or
Equipment
In addition to the
boiler systems and
external treatment
system, concerns
about FAC occurrence
conditions ad
susceptibility of
threaded connections
added
2020 Edition
b) Corrosion in the condensate return system as well as in process unit
reboilers and associated piping may be due to carbon dioxide, although
oxygen pitting from oxygen contamination is also possible as well as
FAC if the proper conditions are present.
c) Threaded connections are especially susceptible.
Classification: Internal Use
DM# Boiler Water and Steam Condensate
Corrosion
Changed Para.
2020 Edition
Appearance or
Morphology of DM
Additional point for
the appearance and
location of FAC
added
API 571, 2020
d) FAC failures are often located in areas where there is a flow
disturbance such as an orifice run, flow meter, elbow, reducer, or
other types of fittings.
The wall thinning occurs just downstream of these flow
disturbances, leaving behind a corroded surface free of oxide scale,
sometimes with a specific flow pattern. FAC has led to rupture of
piping.
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DM# Boiler Water and Steam Condensate
Corrosion
Changed Para.
2020 Edition
Prevention and
Mitigation
Recommendations
to avoid FAC by
marinating pH value
9.2 to 9.6 or by
material upgrade to
Cr-Mo steel
API 571, 2020
e) The pH, temperature, and oxygen concentration are the main
parameters that can affect the potential for
FAC. BFW pH from 9.2 to 9.6 is often recommended. Upgrading the
material to Cr-Mo steel usually solves the problem.
Too low or total absence of oxygen is no longer considered the best
corrosion control for BFW and condensate. Oxygenated treatments
that deliberately inject oxygen into the condensate and BFW
system or the use of oxygen scavenger at reduced concentrations
may be necessary to maintain oxygen levels within the desired range
to mitigate FAC.
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DM# Boiler Water and Steam Condensate
Corrosion
Changed Para.
2020 Edition
Prevention and
Mitigation
Recommendations for
the Boiler Blow down
and water sampling
added
c) Boiler water needs to be blown down to control the concentration
of solids and non-condensable gases.
Steam equipment should be checked to ensure there are working
non-condensable vents. It is also important that steam piping and
equipment allow for blowdown of condensation.
d) Water treatment, sampling, and analysis are the common methods
used to ensure integrity and prevent boiler water and condensate
corrosion.
It may be necessary to modify or improve the water treatment
program if problems such as a ruptured boiler tube or condensate
leaks occur in the boiler water or condensate systems.
API 571, 2020
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DM# Boiler Water and Steam Condensate Corrosion
Changed Para.
Inspection and
Monitoring
2020 Edition
2011 Edition
a) Monitoring the appropriate parameters can indicate
whether the treatment program is performing satisfactorily.
Parameters that can be monitored through analysis include
pH, alkalinity, hardness, conductivity, chlorine or residual
biocide, dissolved gases (oxygen and carbon dioxide), iron,
copper, and total dissolved solids
b) Vacuum testing can be used to check for air ingress into
the condenser hotwell.
c) UT and RT methods can be used to monitor for pipe wall
thinning.
c) Deaerator
cracking problems
can be evaluated
off-line at
shutdowns by
utilizing properly
applied wet
fluorescence
magnetic particle
inspection
d) For boilers, there are no practical online inspection
methods.
UT and RT can be performed on boiler tubes and other
boiler components when the system is offline
API 571, 2020
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DM# Carburization
Changed Para.
Inspection and monitoring
More explanations about the
applicable inspection techniques and
their limitations are considered in
2020 edition
2020 Edition
Check the revised paragraph and explanations in
the RP
Similar to the other embrittlement
DMs, 2020 edition highlighted the
concerns to apply hammering
hardness testing as it may create
brittle fracture initiation site in
heavily carburized materials
API 571, 2020
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DM# Caustic Stress Corrosion Cracking
Changed Para.
Prevention and
Mitigation
Additional point
about the conditions
where Ni Alloys are
susceptible to
caustic SCC in
molten caustic
conditions at high
temperature
API 571, 2020
2020 Edition
c) Nickel-based alloys are more resistant to cracking and may be
required at higher temperatures and/or caustic concentrations.
However, caustic SCC of these alloys has been observed at high
temperatures that promote the formation of molten caustic in the
absence of free water [604 °F (318 °C), at atmospheric pressure]. This
damage has sometimes been referred to as molten caustic cracking.
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DM# Ammonium Chloride and Amine Hydrochloride Corrosion
2011 Edition
Changed Para.
2020 Edition
Critical Factors
Water dew point value
removed and maxi.
temperature for
salting added to be
400F
API 571, 2020
Ammonium chloride salts may
precipitate from hightemperature streams as they are
cooled, depending
upon the concentration of NH3
and HCl, and may corrode piping
and equipment at temperatures
well above the water dew point.
Salting has been observed up to
approx. 400 °F (205 °C).
Ammonium chloride salts may
precipitate from high
temperature streams as they
are cooled,
depending upon the
concentration of NH3 and HCl,
and may corrode piping and
equipment at temperatures
well above the water dewpoint
[> 300°F (149°C)]
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DM# Caustic Stress Corrosion Cracking
Changed Para.
Prevention and
Mitigation
Additional
precautions
added about the
susceptibility of
300 SS if soda ash
is exist at high
temp.
API 571, 2020
2020 Edition
f) Ensure all soda ash (sodium carbonate) solution that may have been
used as a protective measure against polythionic acid stress corrosion
cracking (PTA SCC) in 300 series SS equipment is drained prior to
heating up as this soda ash can result in caustic SCC of 300 series SS as
well as Alloy 800 and Alloy 825 as the water is boiled away.
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DM# Caustic Stress Corrosion Cracking
Changed Para.
Caustic service chart updated as
referenced from NACE SP0403_2015
“Avoid Caustic Stress Corrosion Cracking
of Carbon Steel”
2020 Edition
New area “D” added to the curve allowing
the use of CS without PWHT if the caustic
concentration is less than 2%, regardless
of temperature, and some users use 5%,
as their threshold.
API 571, 2020
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DM# Cavitation
Changed Para.
2020 Edition
Critical Factors
Additional critical factor added
indicating
that
corrosive
environment
can
accelerate
cavitation
API 571, 2020
d) Cavitation taking place in a corrosive environment
can be accelerated by the corrosive effects of the
environment. This is often referred to as cavitationcorrosion.
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DM# Cavitation
Changed Para.
2020 Edition
Damage Description
Graphical illustration of
cavitation mechanism added
API 571, 2020
the
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DM# Cavitation
Changed Para.
2020 Edition
Inspection and Monitoring
Additional inspection techniques
included by adding the acoustic
monitoring of turbulent areas
Additional point added highlighting
the difficulty on depending on
thickness measurement of pumps
casing considering the nonuniform thickness profile
API 571, 2020
It can be difficult to get accurate thickness readings
on pump casings or other castings due to their
inherent thickness variability combined with the fact
that inside and outside surfaces may not be parallel
d) Acoustic monitoring of turbulent areas can detect
characteristic sound frequencies associated with
cavitation. The technique is a qualitative method to
determine damage progression.
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DM# Chloride Stress Corrosion Cracking
Changed Para.
Critical Factors
API 571, 2020
2020 Edition
b) Cl− SCC is caused by the inorganic chloride ion
(Cl−) (or other inorganic halide ions such as
bromide, in which case it might be named
differently). Organic chlorides will not directly cause
Cl− SCC, but they can, and typically do, produce
ionic, inorganic chlorides by the processes of
hydrolysis or thermal decomposition (pyrolysis).
Therefore, organic chlorides can lead to Cl− SCC.
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DM# Chloride Stress Corrosion Cracking
Changed Para.
Critical Factors
2020 Edition
2011 Edition
More explanation
about the effect
of temperature
on susceptibility
to Cl SCC
Although there are exceptions at lower
temperatures and even ambient temperature,
particularly with highly cold worked or sensitized
materials, cracking usually occurs at metal
temperatures above about 140 °F (60 °C), and
experience has shown this to be a useful
temperature limit guideline for fixed equipment in
the refining industry.
Cracking usually
occurs at metal
temperatures above
about 140oF (60oC),
although exceptions
can be found at lower
temperatures.
API 571, 2020
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DM# Chloride Stress Corrosion Cracking
Changed Para.
Affected Units or
Equipment
2020 Edition
e) External Cl− SCC can occur on insulated 300 series SS surfaces when
insulation gets wet.
The operating temperature range of most concern for external Cl− SCC is
140 °F (60 °C) to 400 °F (205 °C).
API 571, 2020
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DM# Corrosion Under Insulation (CUI)
Changed Para.
Affected Materials
400 series SS
added to the list of
the affected
materials
API 571, 2020
2020 Edition
Carbon steel, low-alloy steels, 300 series SS, 400 series SS,
and duplex stainless steels
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DM# Corrosion Under Insulation (CUI)
Changed Para.
Critical Factors
Temperature range for
the susceptibility of SS
changed to be 60-170
C matching the values
in API RP 583
In addition the
statement of the
critical temperature
range changed to be
less restrict showing
that this is the range
where refineries focus
on CUI
API 571, 2020
2020 Edition
For 300 series SS and duplex SS ,
where Cl− SCC is the concern, refiners
generally focus on the temperature
range of 140 °F (60 °C) to 350 °F (175
°C).
2011 Edition
It affects externally insulated
piping and equipment and
those that are in intermittent
service or operate between:
1) 10°F (–12°C) and 350°F
(175°C) for carbon and low
alloy steels,
2) 140ºF (60°C) and 400ºF
(205°C) for austenitic
stainless steels and duplex
stainless steels
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DM# Corrosion Under Insulation (CUI)
Changed Para.
Prevention and
Mitigation
Guidelines added for
the selection of the
insulation material
with Both water
absorption properties
and water retention
Characteristics.
API 571, 2020
2020 Edition
d) Careful selection of insulating materials is important. Both water absorption properties and
water retention characteristics are important and should be considered. Some insulating
materials absorb little water but still trap water against the pipe or equipment for an extended
time because water removal is slow.
While closed cell foam glass materials will hold less water and, therefore, might be less prone
to causing CUI, studies
show that an open cell structure provides a path for water vapor to escape faster, allowing the
insulation to dry quicker. Faster drying time, corresponding to less metal wetting time, should
help mitigate CUI.
1- Types of open cell insulation that limit and delay water ingress have been developed.
2- Water absorption and retention properties of insulation materials can be tested per EN
13472 or ASTM C1134.
e) Insulation with added corrosion inhibitor is available.
f) Low-chloride insulation should be used on 300 series SS to minimize the potential for pitting
and Cl− SCC.
1- Some manufacturers supply insulation certified to be low chloride. Thermal insulation
materials can be tested per ASTM C871 to evaluate chloride content and/or ensure it satisfies a
specified limit.
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DM# Creep and Stress Rupture
Changed Para.
Description of
Damage
2020 Edition
At high temperatures [typically greater than half the absolute
melting temperature in °R (°K)], metal components can
continuously deform under load, even below their elastic yield
stress. This time-dependent deformation of stressed components
is known as creep.
API 571, 2020
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DM# Creep and Stress Rupture
Changed Para.
Critical factors
Explanation added
for the effect of
the coarse gains
API 571, 2020
2020 Edition
1- Because a coarse-grained material has less grain boundary surface
area than a fine-grained material, a material heat treated to have a
coarse-grained structure will generally have better creep strength than
the same material with a fine-grained structure.
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DM# Creep and Stress Rupture
Changed Para.
Inspection and
Monitoring
Additional
inspection
techniques added
for the fired
heater tubes
API 571, 2020
2020 Edition
In-line inspection (smart pigging) of heater tubes will provide a more
complete assessment of remaining wall thickness and diameter
growth. However, it is unlikely to detect internal creep damage, and
further NDE may be needed.
Automated inspection devices (crawlers) are commercially available for
inspecting hydrogen reformer heater tubes. The selection of such
equipment for inspection, as well as analysis and interpretation of
results, involves careful evaluation
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DM# Dealloying
Changed Para.
Affected unit or
equipment
Conditions of
Denickelification
of 400 alloy added
API 571, 2020
2020 Edition
Alloy 400 exposed to HF acid in HF alkylation plants can be
susceptible to denickelification, particularly above 300 °F (50 °C)
or if oxygen is presentinterpretation of results, involves careful
evaluation
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DM# Dealloying
Changed Para.
Affected Materials
2020 Edition
CI removed from
the list of the
affected materials
as it is covered
under Graphitic
Corrosion DM
Primarily copper alloys
Primarily copper alloys (brasses and
bronzes and Cu-Ni alloys) as well as Alloy (brass, bronze, tin) as
400.
well as Alloy 400 and
API 571, 2020
2011 Edition
cast iron.
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DM# Dealloying
Changed Para.
Prevention and
Mitigation
2020 Edition
Added point for
the prevention of
Al-Bronze
dealuminization
Dealuminification of aluminum-bronze can be prevented by heat
treatment to produce an alpha and Beta microstructure
API 571, 2020
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DM# Dealloying
Changed Para.
2020 Edition
Table for combination
of alloys and
Environment subject
dealloying
Table updated by
removing the CI as it
is covered under
Graphitic Corrosion
DM
API 571, 2020
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End of Part 1
Thank You
Baher Elsheikh
Baher Elsheikh @