EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Degradation mechanisms
This document gives the description of the degradation mechanisms credible in EP Europe.
The purpose of these is to provide guidance for Risk Based Inspection (RBI) assessments
(see CMS work instruction EPE.INSP.WI.02.12) as well as reference for Corrosion
Management Framework (CMF).
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Age Related
ATCR
WET-CO2-CR
CUI
ERO-CR
ERO-SND
ORG-AC-CR
OX-CR
SEAWTR
UND-DEP-CR
Non- Age Related
Atmospheric corrosion
Carbon Dioxide Corrosion
Corrosion Under Insulation
Erosion Corrosion
Erosion by Sand
Organic Acid Corrosion
Oxygen Corrosion
Seawater Corrosion
Under Deposit Corrosion
BRITFRACT
CL-SCC
FAT
GALVANIC
HEMB
HIC/SOHIC
LMC
MI-CR
POLYFRACT
SENS
SOIL-CR
STRAYCUR
SSC
Brittle Fracture
Chloride Stress Corrosion Cracking
Fatigue
Galvanic Corrosion
Hydrogen Embrittlement
Hydrogen Induced Cracking
Liquid Metal Embrittlement
Microbiological Induced Corrosion
Polymeric Fracture
Sensitisation
Soil Corrosion
Stray Current Corrosion
Sulphide Stress Corrosion Cracking
Descriptions of “Other” Degradation Mechanism (Secondary importance in E&P operations)
Age related (AR):
An inspection interval can be determined based on a corrosion rate.
Non-age related (NAR): Degradation mechanism requiring monitoring,
“Methodology of Inspection” (contents of the block by inspection) is based on the expected
degradation morphology, but will also be dependent on dimensions, accessibility and material
properties.
Revision control:
Revision
Date
1
2
23-08-2007
10-06-2008
Scope of change
CL-SCC – Variables - Update of max. defined temperature for 22Cr Duplex
Small corrections and formatting; Updating Definitions & DM-matrix.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
ATCR
Atmospheric Corrosion
Description
Susceptible
Materials
Atmospheric corrosion is primarily external corrosion or ‘weathering’ of
metal exposed to air under the prevailing environment conditions.
Usually it is a combination of oxygen, galvanic and/or crevice corrosion
and acid corrosion (dilute sulphuric acid)
Carbon steels, low alloy steels and copper alloyed aluminium and
stainless steels
Variables
Temperature
Pressure
Flow Rate
Moisture/
Humidity
Pollution
Environment
Surface
condition
Location
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
No clear relationship between ambient temperature and
atmospheric corrosion has been established. However, frequent
fluctuations in temperature, with the resulting variations in
humidity and occurrence of condensation, can be of greater
significance than average ambient temperature
N/A
N/A
The presence of water is the dominant factor in atmospheric
corrosion.
Industrial pollution, in the form of sulphur dioxide, significantly
increases the rate of atmospheric corrosion of carbon steels.
The presence of salt spray in the air results in higher corrosion
rates i.e. marine environment.
The presence of mill scale on carbon steel can give increased
pitting corrosion rates, particularly in moist marine or heavily
polluted industrial environments.
Areas, which can get wet and/or accumulate water/seawater, and
breakdown of coating system, are the most likely locations of
occurrence.
Atmospheric corrosion of carbon steels is characterised by general wall
thinning and pitting. Figure 1 shows example of atmospheric corrosion.
Proper surface preparation and coating/painting application and
subsequent maintenance are critical for long-term protection of carbon
steel. Preservation of carbon steel in the yard using inhibitors is also
applied.
Using resistant materials such as duplex stainless steels and aluminium
alloys with 3 to 5% magnesium or the grades with > 99% Al, can reduced
susceptibility of atmospheric corrosion.
See Methodology of Inspection
N/A
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
BRITFRACT
Brittle Fracture
Description
Low temperature embrittlement or brittle fracture is the sudden rapid
fracture under stress (residual or applied) where the material exhibits little
or no evidence of ductility or plastic deformation [API RP 571]
Carbon steel and low alloy steels are of prime concern, particularly older
steels. Ferritic, duplex and martensitic stainless steels (AISI 400 series)
are also susceptible.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Grain size
Surface
conditions
Stress and
strain
Material
condition
Material
thickness
Location
Brittle fracture is most likely to occur at temperatures below the
ductile-to-brittle (or Charpy impact) transition temperature, the
point at which the toughness of the material drops off sharply.
This transition is apparent for all body centred cubic - materials (α
and δ).
N/A
N/A
Grain size can have a significant influence on toughness and the
resistance to brittle fracture.
The size, shape, presence of stress raisers such as flaws,
grooves and sharp edges can affect the susceptibility of materials
to brittle fracture
The amount of residual and applied stresses in steels contributes
to fracture propagation.
Susceptibility to brittle fracture may be increased by the presence
of embrittling phases or (poor) steel cleanliness.
Thicker material sections have a lower resistance to brittle
fracture due to the increased triaxial stresses produced at the
crack tip by the higher constraint.
Susceptible systems are those operating at low temperature such as
refrigeration units, blowdown piping and gas or high gas/oil ratio flowlines
under ‘cold start-up’ conditions, but brittle fracture can also occur at
ambient temperature hydrotesting due to high stresses and low
toughness at the testing temperature.
Susceptible locations are at stress raisers such as flaws, grooves and
sharp edges on the surfaces of piping and equipment.
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Evaluation
Cracks are typically straight, non-branching and largely devoid of any
associated plastic deformation. Microscopically brittle fracture is
composed largely of cleavage, with limited intergranular cracking and
little or no microvoid coalescence.
For new equipment, low temperature embrittlement can be prevented by
materials selection. For example, fine-grained low alloy steels, such as
seamless pipe of ASTM A333 Gr.6, are used in low temperature service
down to –50oC (piping class LT50). The minimum design temperature
limits of materials are detailed in DEP 30.10.02.31-Gen. ‘Metallic materials –
Prevention of brittle fracture’. Proper design detailing can also help to
reduce the susceptibility to brittle fracture e.g. by using a heater during
cold start up.
For existing equipment identified as potentially at risk, care must be taken
to control the operating conditions to minimise its failure susceptibility.
Inspection is not normally used to mitigate brittle fracture.
Susceptible equipment should be inspected for pre-existing flaws/defects,
particularly at locations of high stress.
Tool for corrosion evaluation is not applicable. However, it is
recommended to perform risk assessment.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
WET-CO2-CR
Carbon Dioxide (CO2) Corrosion
Description
Susceptible
Materials
When carbon dioxide present in gas (or oil) dissolves in water it forms
carbonic acid, which reacts with steel and forms iron carbonate.
In systems where both CO 2 and H2S are present, there is an interaction
between the two corrosion mechanisms, depending on the relative
amounts of each acid gas. Regardless of the ratio, if a protective film is
not maintained, the corrosion rate will be similar to the unmitigated CO 2
corrosion rate (SGS Canada Corrosion Degradation)
For more information please refer to: DEP 39.01.10.11-Gen – Selection
of Materials for Life Cycle Performance.
Most commonly in carbon or low-alloy steels. When pH is lower, pitting
may occur in stainless steels.
Variables
Temperature
At elevated temperature, the solubility of CO2 and scale decrease
and the kinetics of precipitation accelerate. There is a tendency
for scale formation at around 70°C but the presence of chlorides
in the water may prevent formation of a stable adherent scale
layer. Above 70°C, break down of the iron carbonate film can
occur leading to ‘mesa’ attack. Figure 1 shows the influence of
temperature on corrosion rates.
Figure 1: Effects of temperatures on corrosion rates
Pressure
Flow Rate
pH
Morphology
Increased partial pressure increases the solubility of CO 2 in the
system which leads to lower pH and hence a higher corrosion
rate.
Corrosion rate increases with increase in water phase flow rate.
Tendency to scaling is increased when pH is above 5.
(NAM Corrosion Degradation Library 1998).
Manifests itself in many forms; general wall thickness loss, ‘mesa’- type
attack, grooving and pitting. Grooving occurs due to water hold-up and/or
insufficient corrosion inhibitor. Preferential weld or HAZ attack may also
occur especially in nickel or silicon containing welds (See Appendix 12 of
DEP 39.01.10.11-Gen). Pitting is common where the effects of CO 2 and
H2S corrosion combined (NAM Corrosion Degradation Library 1998).
Figure 2 shows examples of CO2 corrosion.
Figure 2: pictures 1(a) and (b) are examples of CO2 corrosion of carbon steels
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Corrosion Degradation Mechanisms
Location
Mitigation
EP200703200907 – June 2008
Oil and Gas production systems at high velocities, in laminar flow
pipelines or under conditions of liquid impingement e.g. at bends, tees or
down stream flow/pressure control valves. The bottom of the line (BOL)
will normally suffer a localized attack, whereas the top of the line (TOL)
will likely suffer uniform corrosion. The rate of which is determined by the
rate of water condensation.
Corrosion inhibition can reduce the corrosion rate to < 0.2mm/year.
In gas production systems, the adherence of corrosion inhibitor film
persistency on steel surface may be compromised at (bulk gas) velocities
> 20m/s. However, some increase in this velocity threshold may be
possible by increasing the concentration of corrosion inhibitor.
The performance of inhibitors at higher velocities requires additional
testing. The use of inhibitors requires appropriate inspection and
monitoring to confirm the effectiveness. Corrosion allowance is often
used in conjunction with corrosion inhibition. One must recognize that,
under conditions of stratified flow continuous inhibitor alone will not
mitigate TOL corrosion and that a batch inhibition program may be
required. Injection of a neutraliser for pH control is sometimes used as an
alternative to corrosion inhibition in wet gas systems. The presence of
alcohol/glycol in the water inhibits corrosion.
Resistant Material is also widely used against CO2 corrosion. Stainless
steels with minimum 12% of chromium are used for downhole tubing and
Xmas trees, 22Cr duplex stainless steel is used for production flow lines
and heat exchangers. Vessels can have a corrosion resistant alloy (CRA)
liner/cladding of e.g. 316 austenitic stainless steel or nickel alloy.
Water removal (Dehydration) is also carried out prior to export of oil and
gas. Insulation and heat jacketing can be used to keep metal
temperatures above the dew point to avoid condensation.
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
In some specific circumstances, Cathodic Protection and/or internal
Coating/Painting can be used for protection e.g. separators and storage
tanks with a free water phase.
Appropriate use of NDE methods such as ultrasonic (UT) and
radiographic (RT) inspection can be used. Also corrosion monitoring and
analysis of produced fluids for residual corrosion inhibitor.
See Methodology of Inspection
CORRAT – Corrosion rate assessments for piping/vessels and
preliminary assessments for pipelines can be obtained based on flow
rate (Q), pressure (P), temperature (T), and CO 2 composition of a
system.
HYDROCOR 2007 – A more sophisticated spreadsheet for pipelines and
downhole tubing analyses, which can take into account the presence of
formation water, alcohol, inhibitors and water composition. Hydrocor can
be used for sweet gas with trace H2S (CO2 to H2S ratio > 5000).
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
CL-SCC
Chloride Stress Corrosion Cracking
Description
Stress corrosion cracking in a chloride-containing environment with or
without oxygen occurs when chloride ions electrochemically interact with
the protective oxide layer on stainless steels causing it to breakdown.
For more information please refer to: GS.05.50675
Susceptible
Materials
Austenitic stainless steels such as type AISI 304 or 316, Fe-Cr-Ni alloys
with less than 40 % Ni, 22Cr duplex and 25 Cr stainless steels.
Variables
Temperature
Pressure
Flow Rate
Oxidiser
Stress
Environment
Acidity
Location
Morphology
Mitigation
18Cr-8Ni, 18Cr-10Ni-2Mo steels-max. defined temperature 50°C
22Cr Duplex - max. defined temperature 80°C
25Cr Duplex - max. defined temperature 110°C
Note: 10ºC has been taken out for safety assessment purposes.
See below under ‘Stress’
Non-flow rate related.
The presence of an oxidizing agent, normally oxygen, is
necessary to initiate CL-SCC. There is no threshold oxygen
concentration and CL-SCC can initiate at low (ppb) dissolved
oxygen levels.
The risk increases with the tensile stress levels. These stresses
may either be primary (pressure, external load) or secondary
(residual welding stresses, bending stresses). Internal claddings
or overlays materials are generally considered to be under
compress stress and much less susceptible to CL-SCC but their
resistance is not guaranteed.
Presence of chlorides above 10mg/l increases the likelihood of
CL-SCC attack. Enrichment of chlorides can result from the
evaporation of rainwater through failed insulation or process fluids
via a leaking flange.
Cracking is most likely to occur under acidic pH conditions or at
neutral conditions in the presence of oxygen.
Areas with high stresses e.g. welds and bends.
Transcrystalline (and/or intercrystalline) often branched cracks initiating
from pits at the surface in contact with the corrosive medium (Figure 1).
At the surface, the degradation is often visible as clusters of very fine
cracks. The crack usually undergoes extensive branching and develops
in a direction generally perpendicular to the stress.
Coating/Painting systems are the main barrier for external CL-SCC.
If a coating system is considered, a normal paint system (conventional
coatings system) should not be used; a ‘life-time’ type of coating such as
thermal spray aluminium (TSA) should be used.
A resistant material is an alternative barrier for both internal and external
CL-SCC when the operating temperature exceeds the temperature
threshold limits mentioned above (e.g. Alloy 825, Alloy 625 or other
Nickel alloys).
Initiation of CL-SCC on internal surfaces is avoided in water free system
(Dehydration).
Methodology
of Inspection
The risk of initiation of CL-SCC on external surfaces can be reduced
where
i. Equipment is installed indoors or inside an enclosure (Dehydration).
ii. External condensation on insulated surfaces is prevented.
iii. Avoidance of water ingress at areas of failed coating or where
inspection is difficult.
iv. Avoid crevices, which could allow concentration of chloride ions.
v. Verify that the type of heat tracing does not over heat the external
surface or fail inside the insulation.
vi. Washing the external surface to remove any salt build up.
v. No copper tubing should be used in combination with stainless steels,
as copper ions make stainless steel more susceptible to pitting corrosion.
See Methodology of Inspection
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Corrosion Degradation Mechanisms
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
N/A
Figure 1: Example of chloride stress corrosion.
cracking
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
CUI
Corrosion Under Insulation
Description
Susceptible
Materials
Corrosion under insulation (CUI) occurs when water enters external
insulation as the result of holes or gaps in the insulation covering or when
moisture in the air condenses on the metal surface below the insulation
(sweating). For more information please refer to: GS.05.50675
Carbon steel, Cr-Mo steels, low nickel steels, low alloys up to an
including 9 chrome alloys.
Variables
Temperature
Operating Condition
Operating
Tem perature
T < -5 oC
-5oC>/=T <60oC
60oC>/=T <
120oC
T >/=120oC
Deluge
System
Cyclic
Temperatur
e
Insulation
Damage
Default CR
0,1
No
No
Yes
Yes
No
Yes
0,1
No
Yes
Yes
0,11
Yes
Yes
Yes
0,14
No
No
Yes
0,38
Yes
No
Yes
0,51
No
Yes
Yes
0,57
Yes
Yes
Yes
0,7
No
Yes
No
No
Yes
Yes
0,57
No
Yes
Yes
0,86
Yes
Yes
Yes
1,05
No
Yes
No
No
Yes
Yes
0,38
No
Yes
Yes
0,57
Yes
Yes
Yes
0,7
0,76
0,51
Table 1: Default corrosion rates for offshore location*.
Operating Condition
Operating
Tem perature
Deluge
System
Cyclic
Temperature
Insulation
Damage
Default CR
T < -5 oC
No
No
Yes
0,11
Yes
No
Yes
0,15
No
Yes
Yes
0,17
Yes
Yes
Yes
0,21
No
No
Yes
0,57
Yes
No
Yes
0,76
No
Yes
Yes
0,86
Yes
Yes
Yes
1,05
No
Yes
No
No
Yes
Yes
1,33
No
Yes
Yes
2
Yes
Yes
Yes
2,44
No
Yes
No
No
Yes
Yes
0,57
No
Yes
Yes
0,86
Yes
Yes
Yes
1,05
-5oC>/=T <60oC
60oC>/=T <
120oC
T >/=120oC
1,78
0,76
Table 2: Default corrosion rates for offshore location*.
*Note:




Pressure
Flow Rate
Heat Tracing
Environment
Based on Excor models Rev. 12 and ECM version
Selection of conservative outputs (Rev. 12)
Operational Condition Scenarios Selected
Assumption
Rainfall Onshore < Offshore (700mm/yr v’s 1200 mm/yr)
Corrosion under insulation may occur from –5°C to 175°C
and cyclic temperature (Ref.: GS05.50675). The highest
corrosion rates are experienced in the 50-110°C range where
rates go to 1mm/year occurred in severe case, although rates are
typically in the order of 0.25-0.50 mm/year. Outside of this range,
rates typically decrease to 0.05-0.25mm/year.
Table 1 and 2 refer show corrosion rate for on and offshore
locations, which should be used to provide remaining life
projections. The default corrosion rate for non-insulated steel at
temperature < 150ºC and ≥ 150ºC are 0.5 and 0.15mm/year.
N/A
N/A
Steam tracing failure defeats all barriers. When it fails inside the
insulation, it introduces moisture, strips away coatings and
provides worst case of CUI and CL-SCC. Stainless steel heat
tracing is vulnerable to CL-SCC at similar conditions to CUI.
Sites with high annual rainfall or warmer, marine locations,
airborne contaminants (such as chloride ions) are prone to CUI.
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Corrosion Degradation Mechanisms
Location
Morphology
Mitigation
EP200703200907 – June 2008
Protrusions extending through the insulation sheathing, damage
insulation, piping/equipment with damages steam tracing, localised
damaged coating systems, damaged weather proofing, locations where
moisture/water naturally collected, improper terminated fireproofing.
Carbon steel: localised wall thinning, which is sometimes difficult to
assess because corrosion product might hide the extent of the damage.
Austenitic stainless steel: localised pitting corrosion, where the pits can
be narrow and deep. Figure 1 shows some examples of CUI.
Appropriate Coating/Painting system should be used for all insulated
components, which include underground piping. Refer to DEP 30.48.00
31 EPE External Protective Coatings for on-and-offshore Facilities, and
EP200506217947 EPE Approved Coating Systems for On-and Offshore
Facilities.
Use resistant materials such as GRE and stainless steel for drain system.
Careful selection of insulation, for example insulation that meets ASTM
C-795
for
300
series
stainless
steels.
Maintaining
of
insulation/sealing/vapour barriers to prevent moisture ingress. Refer to
DEP 30.46.00.31 GEN ‘Thermal Insulation (amendments / supplements
to the CINI handbook)’ for thermal insulation selection.
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Proper selection of heat tracing and checking systems that have a
tendency to inflict damage to insulation jacketing providing a path for
water ingress can help to reduce CUI attack.
See Methodology of Inspection.
For CUI a strategy based approach is applied.
Excor models Rev. 12 and ECM version.
Please contact Stefan Lewandowski for further information.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
ERO-SND
Erosion by Sand
Description
Sand erosion is a form of degradation where the metal surface (and any
protective scale film) is removed by the abrasive action of sand or other
solid particles carried by the fluid (gas and/or liquid) above critical
velocity. It should be noted that loss of containment due to erosion can
occur very quickly if sand or solids production increases unexpectedly
and quickly, e.g. due to the use of propant in well interventions or change
in the basic formation sand production.
All materials, metal alloys and refractory.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Sand
Concentration
Sand Particle
Size
Piping
Geometry
Metal/Alloy
Type and
Corrosion
Location
Morphology
N/A
-Change in system pressure may effect flow velocity
Erosion rates for systems with a high gas/liquid ratio are higher
than for systems with a low gas/liquid ratio. It has been shown
that erosion rates for bubbly and churn flow are between 3 and
10 times lower than for annular flow.
In a sand free (see Table 1) and non-corroding multiphase
system, the erosion rate has been shown to be negligible for
bulk velocities up to 80 m/s for CRA’s and 50 m/s for CS.
The erosion rate has been shown to be approximately
proportional to the sand concentration/production rate.
It is generally recognised that particle size can have a
significant effect on the erosion rate. Refer to SGS report
OP.99.20022.
Erosion rates are higher for bends than for reducers or other
internal diameter restrictions, such as reduced bore valves. The
erosion rate for (1.5D) elbows has been shown to be
approximately 10 times higher than for 5D bends.
Erosion rate of a material is linked to its corrosion resistance.
For example, at high bulk velocities in wet gas and/or oil
production piping, the sand ‘erosion’ rate will be higher for
carbon steel than for a corrosion resistant alloy, such as duplex
stainless steel. In practice, the measured reduction in wall
thickness will be the combined value of sand erosion corrosion.
In any ‘sand producing’ facility, the sections of piping or flowlines, which
have the combination of highest sand concentration and high velocity,
should be investigated. In addition to inspection of the tightest 90° bends
(elbows) and Tee pieces, high sand erosion rates can occur downstream
of flow or pressure control /choke valves. For gas flowlines, there have
also been instances of erosion of the inlet side (gallery) of PCVs. For
bends and elbows, the greatest wall thinning will be on the outer radius
45 to 55 from the upstream end and, for 5D bends; a secondary area of
attack is likely near to the downstream end of the bend.
In sand containing water systems, erosion attack of (centrifugal) pumps is
likely.
Erosion attack due to sand is characterised by localised wall thinning and
a smooth appearance of the eroded surface. Figure 1 show example of
erosion by sand.
Figure 1: Example of failure due to erosion by sand
Mitigation
Erosion allowance, using resistant materials, proper flow control and
careful design (target tees, long radius bends etc.) detailing can help to
mitigate failure due to erosion by sand.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
See Methodology of Inspection
i.
FIST (Semi quantitative tool to predict sand production).
ii.
Tulsa SPPS4 shall be used for sand erosion rate prediction.
Any deviation from the above tool shall be referred to relevant
Shell Technical Authority for Approval.
Oil
Gas
Continuous
Peak
(~ 0.5 day)
Continuous
Peak
(~ 2 hrs.)
“Sand free”
~0.1 g/bbl
(~0.25 pptb)
~1 g/bbl
(~2.5 pptb)
~0.2 kg/Mm3
(~0.01 lb/Mscf)
~2 kg/Mm3
(~0.1 lb/Mscf)
Some sand
~1-10 g/bbl
(~2.5-25 pptb)
~10-100 g/bbl
(~25-250 pptb)
High sand
20+ g/bbl
(50+ pptb)
200+ g/bbl
(500+ pptb)
~2-20 kg/Mm3
(~0.1 - 1 lb/Mscf)
40+ kg/Mm3
(2+ lb/Mscf)
~10-100 kg/Mm3
(~0.5 - 5 lb/Mscf)
200+ kg/Mm3
(10+ lb/Mscf)
Note: pptb = pound per thousand barrels
Table 1: Guidance on definition of ‘sand free’, ‘some sand’ and ‘high sand’. It should be
emphasized that application of these guidelines requires good engineering judgement.
Contact Sand Management Team or Shell Technical Authority for further information.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
ERO-CR
Erosion Corrosion
Description
Erosion Corrosion is a description for the damage that occurs when
erosion contributes to corrosion by removing protective films or scales, or
by exposing the metal surface to further corrosion under the combined
action of erosion and corrosion
All materials, alloys and refractory. Softer alloys are easily worn from
mechanical damage may be subject to severe metal loss under high
velocity conditions. Increasing hardness of metal substrate is not always
a good indicator of improved resistance to erosion, particularly where
corrosion plays a significant role.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Temperature is one of the factors influencing the corrosivity of
environment and stability of surface films.
N/A
Erosion Corrosion can occur in flowing slurry or gas solid
systems. Even very low flow rates (e.g. 1.5m/s) are sufficient to
cause erosion (Corrosion degradation mechanism from SGS
Canada).
Table 1 illustrate the relative susceptibility of a variety of metals
and alloys to erosion corrosion by seawater at different velocities.
Material
Carbon steel
Cast Iron
1fps(tidal current)
6
4fps (immersed in
seawater flume)
13
27fps (rotating
disk)
47
9
-
54
Silicon Bronze
0.2
0.3
57
Admiralty brass
0.3
3
29
Hydraulic bronze
1
0.2
55
G bronze
1
0.3
46
Al bronze
1
-
44
0.4
-
19
90-10 Cu Ni
1
-
16
70-30 Cu Ni
(0.05% Fe)
70-30 Cu Ni
(0. 5% Fe)
Monel
0.3
-
32
<0.2
<0.2
6
<0.2
<0.2
1
0.2
0
<0.2
<0.2
-
0.05
0
-
0
Aluminium brass
316 SS
Hastelloy C
Titanium
Note: 1fps ≈ 0.3 m/s; 1 mil ≈ 0.025mm
Table 1: Typical erosion corrosion rate in seawater, mpy(mils per year).
(Ref. ASM Metals Handbook, Volume 11, Failure Analysis and
Prevention, ASM) International, Materials Park, OH).
Environment
Location
Morphology
Increasing the corrosivity of the environment may reduce the
stability of protective surface films and increase the susceptibility
to metal loss. Metal may be removed from the surface as
dissolved ions, or as solid corrosion products, which are
mechanically swept from the metal surface. Changing in pH can
contribute to the corrosivity.
Areas of high velocity and/of impingement, such as elbows, tubing, flow
lines, pipe fittings, headers, valves, pumps and other production
equipment.
Localised thinning and pitting
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Corrosion Degradation Mechanisms
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
The erosion rate can be reduced by using more corrosion resistant alloys
and/or altering the process environment e.g. dehydration, solid removal
or flow (i.e. velocity) control.
Dehydration in a system can also help to reduce the corrosivity of the
environment.
Improved design involves changes in shape, geometry and materials
selection.
See Methodology of Inspection
N/A
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Corrosion Degradation Mechanisms
FAT
Fatigue
Description
Susceptible
Materials
Fatigue occurs by the application of cyclic stresses e.g. from internal
pressures, mechanical loading, structural vibration or thermal cycling,
leading to progressive damage and eventually failure by crack growth.
All materials can be susceptible to fatigue by repetitive cyclic stresses or
thermal cycling.
Variables
Temperature
Pressure
Flow Rate
Stress level
Amplitude
Number of
Cycle
Fluctuation of temperatures. As a practical rule, cracking may
be suspected if the temperature swing exceed about 93°C [see
API RP 571]
Pressure cycling can induce fatigue
N/A
A material subjected to high stress can fail at low cycle or vice
versa.
Relative movement (mechanical fatigue) or differential
expansion (thermal fatigue) is constrained can lead to fatigue
failure.
7
Figure 1:
shows fatigue
behaviour of
different
materials.
Stress
6
5
Ste e l
4
Notche d ste e l
3
2
Nonfe rrous
1
0
1,E+03
1,E+04
1,E+05
1,E+06
1,E+07
1,E+08
Number of cycles for failure
Metallurgical
and
microstructure
Design
Location
Fatigue failure is usually originated at the metal surface.
Any major change on the surface such as the presence of
inclusion, and discontinuities can degrade fatigue resistance.
Fatigue may be enhanced by repetitive breaking of the oxide
layer. Finer grain microstructures tend to perform better than
coarse grained.
Stress raisers such as notches will decrease fatigue strength.
Mechanical notches, tool markings, grinding marks, threads can
reduce fatigue strength.
Any components subjected to repetitive cyclic stresses or thermal cycling
e.g. pumps, turbines, compressors, engines, wellhead chokes etc.
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Thermal fatigue cracks are generally wide and often filled with oxides due
to elevated temperature exposure. Cracks may occur as single or
multiple cracks. Signature marks of mechanical fatigue failure ‘Clam
Shell‘ type fingerprint that has concentric rings called ‘beach marks’
(Figure 2) Figure 3 shows an example of Tungum tube fatigue failure.
Fatigue can be minimized by appropriate design.
See Methodology of Inspection
In S-RBI differentiation of fatigue in Mechanical (MEFAT, includes
Vibration fatigue), Thermal (THFAT) and Corrosion (CORFAT).
Assessent of piping vibration fatigue shall follow the "Guidelines for the
avoidance of vibration induced fatigue failure in process pipework" - 2nd
edition (Jan.2008 - Energy Institute, London)
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Corrosion Degradation Mechanisms
GALVANIC
Galvanic Corrosion
Description
When two different metals are immersed in an electrolyte and connected
through a metallic path, current will flow. These results in the preferential
attack of the more active (less noble, or anodic) metal, while the
corrosion of the other metal (the more noble, or cathodic metal
component) slows down or stops completely.
Any dissimilar metal combination.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Electrolyte
Dissimilar
metals/materi
als properties
Electrical
contact
Oxidiser
Location
Morphology
Mitigation
Temperature may affect on the anode-cathode relationship;
Above 60ºC, the anode-cathode relationship of galvanized steel
reversed.
N/A
The corrosion rate increase with increasing flow rate. In an
aerated solution, the attack is related to the rate of oxygen
diffusion to the surface.
Presence of electrolyte can conduct a current. A continuous
(bulk) phase is required. The corrosion of anode may be
significantly higher immediately adjacent to the connection to
the cathode, depending on solution conductivity. Salt solution
has a higher conductivity than potable water for example.
The presence of two dissimilar metals known as anode (more
active material) and cathode (more noble material), in contact
with an electrolyte. Galvanic corrosion can occur on the same
alloy where there is a distinct difference in local material
properties such as surface films, scale or welded components.
An example of such conditions is an old steel pipe connected to
new steel pipe. The anode to cathode ratio affects corrosion
rate of anode and cathode; the corrosion rates will be less if
there is a large anode to cathode ratio, while small anode to
cathode ratio will result high anode corrosion rate.
An electrical connection must exist between anode and
cathode.
The presence of an oxidizing agent will determine the rate of
attack. Frequently, galvanic attack is limited by oxygen diffusion
to the metal surface i.e. under diffusion control.
This type of attack can occur wherever there is a conductive fluid and
alloys are coupled.
This type of corrosion mechanism consists of internal or external
localized thinning and pitting. It is usually recognized by the localized
attack near the junction on the less resistant metal. Figure 1 shows
examples of galvanic corrosion failures.
The best mitigation for internal and external galvanic corrosion is through
detail designing (e.g. isolation). Dehydration can also mitigate internal
galvanic corrosion. Coating may also act as a barrier for this type of
attack but it is difficult to ensure the coating durability. CP can also be
used as a barrier for external galvanic corrosion.
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Corrosion Degradation Mechanisms
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
See Methodology of Inspection
The electrochemical or galvanic series can be used for an initial appraisal
of the possibility of galvanic corrosion.
Figure 1: shows internal galvanic corrosion due to difference in material properties after the welding process.
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Corrosion Degradation Mechanisms
HEMB
Hydrogen Embrittlement
Description
Hydrogen embrittlement can occur when atomic hydrogen is absorbed
into a metal. The hydrogen dissolves interstitially and restricts dislocation
mobility, which result in a reduction of metal toughness. Embrittlement
usually occurs in combination with residual or applied tensile stresses.
In principal, all metals and most likely to occur in body centred cubic
(BCC) and hexagonal BCC metals such as high strength steels and
titanium (due to hydride formation) where dislocation mobility is
restricted.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Hydrogen
Residual
Stress
Hardness
Defects
Location
Morphology
Mitigation
The effect is pronounced at temperature from ambient to
about 150C. Effects decrease with increasing temperature.
Above 200C the risk of HEMB is very low (H2 development and
subsequent diffusion into metal is very low at low temperature
and therefore HEMB is less pronounced at low temperature).
N/A
N/A
Hydrogen sources can be from welding process, cleaning and
pickling in acid solution, H2S environment and cathodic
protection. Hydrogen development and subsequent H2 diffusion
into metal is very low at low temperature and therefore less
pronounced at low temp.
Sources of residual stresses can come from welding or applied
load or cooling during manufacturing. The presence of residual
stresses and high constraint increases the risk of hydrogen
embrittlement failure.
Susceptibility to hydrogen embrittlement increases with
increasing hardness (usually above Hv 300). Hard
microstructures in the weldment are particularly susceptible to
embrittlement. Certain microstructure such as untempered
martensite and pearlite are more susceptible at the same
strength level than tempered martensite. Carbon steel that is
severely hydrogen charged will have lower toughness than with
no hydrogen.
Defects such as inclusion or lamination will increase the
susceptibility of hydrogen embrittlement. These defect sites
increase internal stresses, and thus the local HEMB is
susceptible at microscopic level.
Wet H2S environment in particular where welds are present (heataffected-zones of a weld) or locations of high residual or tri-axial stresses
such as notches.
Cracking due to hydrogen embrittlement can initiate sub surface but most
cases are surface breaking [API RP 571]. Cracking can be intergranular or
transgranular and can occur at the weld toe. In high strength steel,
cracking is often intergranular. There is often little evidence on a
macroscale prior to failure.
Figure 1: Shows failure of IJsselmonde duplex SS water
injection line was attributed to hydrogen embrittlement.
Proper selection of materials for sour service
is essential. Use low strength steels and
PWHT in a hydrogen free environment to
temper the microstructure, improve ductility
and reduce residual stresses and hardness.
Apply a protective lining or coating; SS
cladding or weld overlay to prevent the
surface hydrogen reactions. Dry environment
will help to reduce the risk of attack. Effective
use of H2S scavenger can also help to reduce
the susceptibility of materials to this kind of
failure. Use low hydrogen, dry electrodes and
preheating methods during welding process
alsodiffused
helps improve
HEM
resistance.
If hydrogen is expected tocan
have
into the
metal,
an elevated
temperature bake out 200°C or higher may be required to drive the
hydrogen out prior to welding. Figure 1 above show an example of failure
due to hydrogen embrittlement.
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Corrosion Degradation Mechanisms
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
See Methodology of Inspection
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Corrosion Degradation Mechanisms
HIC/SOHIC
Description
Hydrogen Induced Cracking/ Stress Oriented Hydrogen Induced
Cracking
HIC occurs when atomic hydrogen generated by the corrosion reactions
is absorbed and diffuses through the steel. Atomic hydrogen then
accumulates as gaseous (molecular) hydrogen at non-metallic inclusions,
particularly when these inclusions have been flattened by rolling
operations, or at bands of segregation or bainite, because hydrogen
molecules are too large to diffuse out. As more hydrogen enters the steel
the internal pressure will rise up to the point where local deformation
occurs. [DEP 39.01.10.11]. The steel around the crack becomes highly
strained and this can cause coalescence of microcracks.
HIC can occur in several forms [API RP 571]:
i.
ii.
iii.
Stepwise cracking –Interconnecting of small HIC cracks at
different depth which often look like a stairs step. The result
is through thickness cracks perpendicular to the surface.
Figure 1a shows example of this stepwise cracking.
Hydrogen blistering – If crack sites are close to the steel
surface, plastic deformation of the ligament between crack
and surface can occur, which result in the formation of a
blister. . Figure 1c shows example of blistering.
SOHIC (Stress Orientated Hydrogen Induced Cracking) Cracking which appears as arrays of cracks stacked on top
of each other. The results are a through thickness cracks that
are perpendicular to the surface and are driven by high level
of stress (residual or applied). They usually appear in the
base metal adjacent to the weld heat affected zones or other
cracks or defects.
Susceptible
Materials
Carbon and low alloys steels (St. Fergus). Also SOHIC in MSS 13 Cr (BP
Norway Tambar Field) due to cathodic protection has been experienced
in EPE.
Variables
Temperature
Pressure
Flow Rate
Hydrogen
Defects
Location
HIC resistant steels need not be specified for equipment that
operates continuously above 65C. Short temperature transition
to below 65C such as during shut down and start up are
considered to be too short to cause HIC [DEP 39.01.10.11].
H2S partial pressure (see hydrogen)
N/A
All these damage mechanisms are related to the absorption and
permeation of hydrogen in steels. Permeation increases with H 2S
content and acidity (pH) and can occur at low H2S threshold
levels below the sulphide stress cracking (SSC) limits.
Presence of inclusions or laminations increases the HIC
susceptibility of steel.
Wet H2S environment, cathodic protection
Morphology
HIC occurs as planar defects aligned in the rolling direction. Stepwise
cracking have stair steps appearance (1a). Hydrogen blisters appear as
bulges on the ID or OD surface of the steel such in figure1 (b) and 1(c).
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Corrosion Degradation Mechanisms
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
Employing a corrosion resistant material especially in sour service
environment can control this type of corrosion. HIC resistant steels can
be used to minimize the susceptibility to blistering and HIC damage.
Detailed materials and fabrication guidance can be found in NACE
Publication 8X194. Effective use of H2S scavenger can help to reduce
this type of attack. Dehydrated environment will eliminate the
susceptibility of the attack. Use steels i.e. materials with less internal
inclusions and discontinuities. PWHT can be used to reduce the effect of
SOHIC damage [API RP 571].
Special Ultrasonic inspection. See Methodology of Inspection.
For HIC/SOHIC a strategy based approach is applied.
HIC risk assessment tool in S-RBI
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Corrosion Degradation Mechanisms
LMC
Liquid Metal Embrittlement
Description
Susceptible
Materials
Liquid metal embrittlement is a form of cracking caused by certain molten
metals coming into contact with specific alloys. Cracking can be sudden
and brittle in nature [API RP 571]. Cracking occurs in very specific
combinations, where a construction alloy comes in contact with a low
melting point metal such as zinc, mercury, cadmium, lead, copper or tin.
It can occur both internally and externally. Internal liquid metal
embrittlement is mainly due to mercury while external liquid metal
embrittlement has mainly resulted from molten zinc on stainless steels.
High strength steel, 300 series SS, nickel base alloys and the copper
alloys, aluminium.
Variables
Temperature
Pressure
Flow Rate
Tensile
Stress
Zinc penetration can occur at temperatures above 400 oC on a
highly stressed alloy surface. [EP2001-5024 – Material Failure
Modes, Mitigation Methods and General Material Properties]
N/A
N/A
High tensile stress promotes cracking. However, cracking can
initiate simply through contacting the molten metal with the
susceptible alloy.
Molten Metal
Susceptible Alloy
300 Series SS and DSS
Copper Alloys
Alloy 400
Aluminium Alloys
Zinc
Mercury
Mercury
Mercury
Molten Metal
High Strength Steels
Cadmium
Table 1: LMC couples susceptible to embrittlement [ASM Metal
handbook,’ Failure Analysis Prevention’ volume 11, ASM International,
Material Park OH].
Environment
Location
Cracking can sometimes occur after contaminated surfaces have
experienced prolonged exposure to liquid metals.
Any locations where the LMC couples are found.
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
LMC failure will appear as brittle crack in an otherwise ductile material.
LMC can only be confirmed through metallography, by the presence of
intergranular cracks, usually filled with low melting metal.
Utilising materials, which are immune or resistant to LMC will reduce both
internal and external LMC risks. All austenitic stainless steel piping and
equipment should be coated with a suitable metallic zinc-free organic
coating. Avoid contact of galvanized components and over spray from
zinc and inorganic zinc coating. Need to avoid galvanized items (e.g.
cable trays) installed above stainless steel piping.
Appropriate NDE methods of crack detection such as magnetic (MT) and
penetrant (PT) testing. See Methodology of Inspection
Not applicable as whenever possible susceptible materials should be
avoided.
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Corrosion Degradation Mechanisms
MI-CR
Microbiologically Induced Corrosion
Description
MIC is a form of corrosion caused by living organisms such as bacteria,
algae or fungi. The most common form of MI-CR is the corrosion of iron
and steel under anaerobic (oxygen free) conditions in the presence of
sulphate-reducing bacteria (SRB). SRB are present in most waters and
all seawaters. They encourage the anodic dissolution of iron by
depolarising the cathode surface (consuming atomic hydrogen to reduce
sulphate ions). SRB form H2S, which then reacts with the surface by
normal corrosion mechanisms.
Most common materials of construction including carbon and low alloy
steels, stainless steels, aluminium, copper and some nickel base alloys
[API RP 571 – Damage Mechanisms Affecting Fixed Equipment in the
Refining Industry]. There has also been incidence of pitting/crevice attack
of CRAs under aerobic biofilms.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Location
Morphology
Bacteria can survive at temperatures ranging from –13°C to
150°C depending on the type of organisms and pH ranging from
0 –12 [API RP 571]. However, SRB actively grow at a reduced
temperature range and are inactive out with the range pH 5 to 9.
N/A
Proper control of flow to minimise low flow or stagnant zones
and/or elimination of deadlegs, can help to reduce incidence and
severity of MIC attack in a system.
Aqueous environment or services where water is sometimes present,
especially where there are stagnant or low-flow conditions. It can also be
found in soils particularly where they are continuously or intermittently
waterlogged.
MI-CR is usually observed as localised pitting under deposits/ tubercles
or biofilm that shield the organisms. Damage is often characterised by
the cup shaped pits. Figure 1 shows examples of MI-CR failure.
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Microbes require water to thrive. The most effective control is keeping the
system clean. A proper flow control and pigging can help to clean the
system. Avoid stagnant areas and dead-legs. Frequently replenished low
flow regions are a particular risk. Systems that contain water (cooling
water, storage tanks, etc) should be treated with biocide. For such
treatments, the monitoring of effectiveness to determine the required
treatment frequency is required. Internal coating, metallic lining or
cladding help to reduce the risk of MI-CR. Keep the system dry can help
to minimise the chance of both internal and external MIC. Effective CP
can help to prevent external MI-CR.
Appropriate use of NDE methods such as ultrasonic (UT) and
radiographic (RT) inspection can be used. Also scraping of coupons /
biostuds, serial dilution and/or analysis of the water (dissolved H2S for
SRB) can be use to monitor. See Methodology of Inspection
Risk assessment for SRB as flowchart
(T. Whitham EPNL April 1996 p. 35-36)
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Corrosion Degradation Mechanisms
ORG-AC-CR
Organic Acid Corrosion
Description
Internal corrosion of metals in free water containing organic acids such
as formic, acetic, propionic, butyric and valeric acids
Carbon steels
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Acid
concentration
Environment
Location
The higher the temperature, the higher the corrosion rate. The
effect is more pronounce at low pH values.
Systems at low pressure
The higher the flows rate the higher the corrosion rate.
The higher the total concentration of organic acid in water, the
higher the corrosion rate. Small amount of water in a
hydrocarbon stream with small amounts of acids in the mixture
can result in high corrosion rates.
Systems at low pressure (low CO2 partial pressure but low pH)
particularly those with no upstream corrosion inhibition.
Gas and oil production facilities
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Corrosion is often uniform on carbon steel. If the water is stagnant and
contains chlorides then, pitting can occur. Heat-affected-zones of welds
or the welds themselves may be preferentially attacked.
As an alternative to the use of resistant materials or CRA cladding,
carbon steel with corrosion inhibition can help to minimise the effects of
this type of attack. Corrosion allowance is often used in conjunction with
corrosion inhibition. Also in gas systems, keeping the operating
temperature above the dew point to avoid condensation can be effective.
Internal coating/painting can also be used for protection e.g. separators
and storage tanks with a free water phase.
Appropriate use of NDE methods such as ultrasonic (UT) and
radiographic (RT) inspection can be used. Also corrosion monitoring and
analysis of produced fluids for residual corrosion inhibitor.
See Methodology of Inspection
Use of CORRAT and HYDROCOR has only limited application for
organic acid corrosion.
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Corrosion Degradation Mechanisms
OX-CR
Oxygen Corrosion
Description
Corrosion due to the presence of dissolved oxygen in aqueous
environments.
Carbon steels, stainless steels in the presence of chloride ions.
Susceptible
Materials
Variables
Temperature
An increase in corrosion rate is expected at higher temperatures
in pressurised systems. In systems open to atmosphere, the
equilibrium oxygen content decreases with increase in
temperature (Figure 1a). Figure 1b shows the effect of
temperature on corrosion rate at lower oxygen concentrations.
Figure1: 1(a) shows effect of oxygen on corrosion rate in an open and
closed system for iron (Corrosion, Cause and Prevention, F.Speller, pg
168, Mc Graw-Hill, New York, 1951). 1(b) shows effect of dissolved
(Corrosion and its Prevention in Waters by G. Butler and H. C. K. Ison,
published by Leonard Hill-London, 1966.oxygen on corrosion rate).
Pressure
Flow Rate
Environment
Location
More oxygen can be dissolved in the water, which might lead to
higher corrosion rate.
The increase of flow will increase corrosion rate due to increase
in the diffusion of oxygen to the metal surface.
The presence of H2S and salt in the system will increase the
corrosion rate. The presence of mill scale on carbon steels can
significantly increase the local corrosion rate.
Any system where oxygen is dissolved in free water, in particular where
the water also contains chloride salts.
Morphology
Corrosion on carbon steel is generally uniform. However, if a scale layer
is formed, wide mouth pitting can occur. Figure 2 shows the effect of
oxygen corrosion in a water injection system.
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Corrosion Degradation Mechanisms
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
Corrosion resistant materials, such as cupro-nickel and non-metallics,
can be used to minimise the effects of oxygen corrosion. Mechanical
deaeration and/or oxygen scavenger can be used to reduce the oxygen
concentration as much as possible in the system. For effective protection
deaeration should be to < 10ppb of oxygen. Avoid condensation in a
system can be used as a barrier for this type of attack.
Appropriate use of NDE methods such as ultrasonic (UT) and
radiographic (RT) inspection can be used. Also corrosion monitoring and
analysis of produced fluids for residual corrosion inhibitor.
See Methodology of Inspection
The graphs above as a first pass estimate.
HYDROCOR 2007
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Corrosion Degradation Mechanisms
POLYFRACT
Polymeric Fracture
Description
Fracture of polymeric materials occurs via brittle, ductile or a combination
of both mechanisms. Un-reinforced thermosetting plastics primarily
fracture in a brittle manner, while thermoplastics may fracture in a ductile
or brittle manner depending on the circumstances (i.e. temperature, strain
rate, etc).
All polymeric materials.
Susceptible
Materials
Variables
Tempera
ture
Pressure
Flow
Rate
Stress
and
Strain
Surface
Condition
s
Environm
ent
If the fracture of a thermoplastic material takes place below its glass
transition temperature (Tg), then the failure mode will be brittle. A
thermosetting material that is heated to elevated temperatures
gradually weakens and would fracture at a lower stress level.
However, fracture would still occur in a brittle manner because the
covalent bonding network (cross-links between polymer chains) is
retained at elevated temperatures.
.
N/A
N/A
Strain rate is an important factor in the fracture behaviour of
thermoplastics. Lower strain rates favour ductile fracture because a
slow strain rate allows for molecular chain realignment. External
stresses such as from mechanical loading, can contribute to fractur e.
The size, shape, presence of stress raisers such as grooves and
sharp edges affecting the susceptibility of fracture of polymeric
materials.
For examples buried GRE, GRP, etc, are exposed to soils that can
be either acidic or alkaline; conditions which can affect the service life
of plastics. When situated above ground, degradation due to UV rays
becomes an important factor to consider in the degradation of
plastics.
Location
Any plastics lines.
Morphology
Failure can occur in a brittle and ductile manner depending on
temperature, stress and strain, as well as the surrounding environment.
Susceptibility to fracture can be reduced by proper materials selections to
use in a specific environment. Careful design can help to mitigate this
type of failure.
See Methodology of Inspection
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
N/A
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Corrosion Degradation Mechanisms
SEAWTR
Seawater Corrosion
Description
Corrosion of alloys by aerated seawater.
Susceptible
Materials
Note: Volts vs Saturated Calomel Electrode
Alloys may become active and exhibit a potential near -0.5 volts in low velocity or poorly
aerated water, and at shielded areas
Figure 1 shows corrosion potentials of different materials when exposed
to seawater.
Electrical continuity between materials with different potentials should be
avoided.
Variables
Temperature
Pressure
Flow Rate
Surface
Scale
An increased in corrosion rate of carbon steel is expected at high
temperature. However, systems open to atmosphere, the
equilibrium oxygen content decreases with increase in
temperature; may counteract the effect of temperature.
N/A
The corrosion rate of carbon steel increases with increase of flow
rate. As flow rates increasing, more oxygen diffuses to the steel
surface. The corrosion rate at the flow of 1,5m/s can be increased
4 times than that of stagnant conditions. Severe localised
corrosion is most likely under stagnant conditions for stainless
steels especially at locations close to the atmosphere/water
interface.
The presence of any mill scale on carbon steels can greatly
increase the local corrosion rate. The corrosion resistance for
both stainless steel and aluminium are dependent on the
presence of oxide scale
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Environment
Location
i.
ii.
iii.
Presence of oxygen is the dominant factor in seawater corrosion.
The growth of muscles and other molluscs may influence
corrosion. When these organisms die, H2S is generated and
where these results in localised high H2S concentrations and
lower pH, the corrosion rate will increase or microbiological
induced or crevice corrosion may occur. The salinity of water for a
closed system can be varied and will influence the corrosion rate.
There is little variation in the salinity of ‘open’ seawater.
Topside seawater systems
Sub sea systems
Severe corrosion usually occurs at splash zone of offshore
structure where maintenance is difficult and costly.
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Carbon steels experience generally wall thinning and pitting while
stainless steel suffer localised pitting. Figure 2 above show an example
of pitting due to seawater.
Material selection is first measure. Effective use of CP system can help to
mitigate this type of corrosion attack. Beside effective CP system, proper
selection of resistant materials, coating system and design detailing can
also be used as barriers against seawater corrosion. Oxygen scavenger
can also be used to combat oxygen corrosion.
See Methodology of Inspection
One way to define the pitting resistance of stainless steels is through the
Pitting Resistance Equivalent, PRE. The PRE number is calculated from
the chemistry of the stainless steel according to the following formula:
PRE=%Cr+3.3%Mo+16%N
Oldfiled, Swales & Todd Oxygen Corrosion Model (very conservative)
AND
For deaerated seawater, Cortest Ltd has developed a model for corrosion
prediction for carbon steel. (SGS Canada).
EPE Oxygen Corrosion Model can be used to calculate seawater
corrosion.
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
SENS
Sensitisation
Description
Susceptible
Materials
Sensitisation occurs when a material is subjected to elevated
temperatures and cooling cycles, such as during annealing, welding, etc.
Sensitisation will result in precipitation, which will influence corrosion
and/or mechanical properties.
Any heat-treatable alloy such as stainless steels, Al alloys, Nickel alloys,
etc.
Variables
Temperature
Pressure
Flow Rate
Thickness
Heat Input
Tensile
Stress
Sensitisation occurs from exposure in the range 450°C to 800°C
dependent on the type of stainless steels.
N/A
N/A
As the thickness of materials increase, the tendency of exposure
time above the temperature range of 450-800°C increases.
The higher the heat input during welding or operation will
increase the severity of sensitisation.
The presence of tensile stress could lead to intergranular attack
[D. A. Jones Principles and Prevention of Corrosion, Prentice Hall
1992]
Location
Heat-Affected-Zones (HAZs).
Morphology
The attack initially starts as pitting corrosion but in the presence of
significant stress operating and residual joint stresses, may lead to
intergranular stress corrosion cracking. Figure 1 shows example of
sensitisation on super martensitic steel. Further details can be obtained
in TWI report no: 14142/9/06
Mitigation
Proper materials selection (use of stabilized, or low carbon, stainless
steels) and proper design can help to avoid this type of failure. PWHT on
welded components can correct the sensitisation by re-solution of
chromium carbides (localised heat treatment may not be successful, as a
new sensitised zone might be created at area adjacent to the sensitised
zone.
See Methodology of Inspection
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
N/A
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
SOIL-CR
Soil Corrosion
Description
Deterioration of metals exposed to soils is referred to as soil corrosion.
[API RP 571]
Carbon steels, cast iron and ductile iron. Table 1 shows corrosion of
some materials in soil.
Susceptible
Materials
Table1: Corrosion rates in soils [H. H. Uhlig, Corrosion and Corrosion Control 3rd Edit,
Wiley, New York Publication, 1985]
Variables
Temperature
Pressure
Flow Rate
Moisture and
Oxygen
Availability
Others
Location
Underground and buried components at areas of coating breakdown.
Morphology
External thinning with localised wall losses due to pitting. The severity of
corrosion depends on the local soil conditions and changes in the
immediate environment along the equipment metal surface. Poor
condition of a protective coating can be a sign of potential corrosion
damage.
Soil corrosion can be prevented by proper selection of resistance
materials, application of coatings and effective use of cathodic protection
(CP). The most effective mitigation is a combination of a corrosion
resistant coating and cathodic protection system [API RP 571 – Damage
Mechanisms Affecting Fixed Equipment in the Refining Industry]. Figure
1 shows example of soil corrosion.
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Corrosion rate increases with increase in metal temperature.
N/A
N/A
Soil-to-air interface areas are often much more susceptible to
corrosion than the rest of the structure because of moisture and
oxygen availability.
As well as moisture content, soil corrosivity is influenced by the
acidity and (dissolved) salt content. Additional factors like the
presence of dissimilar soils, stray currents, differential aeration
corrosion cells and microbiological induced corrosion may be
influential.
Surveys such as DCVG (direct current voltage gradient) and CIPS (close
interval potential survey) can be used to detect coating breakdown of
buried lines. Intelligent pigs can be used for thorough inspection of
pipelines. Alternatively a sample external visual (and ultrasonic wall
thickness) inspection of underground equipment can be carried out by dig
up." See Methodology of Inspection
Soil resistivity comparison can give a ‘broad brush’ assessment of
potential areas of highest corrosion risk.
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
STRAYCUR
Stray Current Corrosion
Description
Stray current corrosion can occur when a continuous metallic structure is
immersed in an electrolytic environment (the sea or buried on the soil)
either due to interference between cathodic protection (CP) systems or
between a CP system and another nearby current path in earth provided
by a low resistance metallic object such as pipeline or a near high voltage
power supply lines.
A stray current path can also be developed when CP insulation joints in
the pipeline/piping system fails due to bridging or short-circuiting.
Buried metal structures.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Design
N/A
N/A
N/A
Design should be made based on the situations all potentials
problems of stray current:
i.
ii.
iii.
iv.
Cathodic protection (CP) system interaction:
Stray current from DC systems. Direct stray current
corrosion, originating from direct current sources
such as DC rail transit systems, DC welding
equipment and cathodic protection systems. In
general, direct stray current corrosion is considered
the most severe form of these problems [1]
Stray current from AC systems originating from
alternating current sources such as overhead ac
power lines [1].
Telluric effects, a "natural" form of dynamic stray
currents induced by transient geomagnetic activity
(disturbances in the earth's magnetic field) [1]
Ref: 1. J.H. Fitzgerald III, "Stray Current Analysis", in Uhlig's Corrosion
Handbook, Second Edition, R.W. Revie Editor, Wiley, 2000.
Location
Morphology
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Any buried components, especially pipeline, where interference by
external electrical system occurs or at an ineffective CP insulation joints.
Typically severe local attack.
Figure 1. Stray current corrosion in monoblock type insulation joint.
Proper coating can help to mitigate stray current corrosion at isolation
joints but the best way is to tackle the problem at the design stage.
Examples are the use of CP insulation joint with adequate length of
electrical separation to prevent shortcutting and the installation of
dedicated earthing facilities in case of interaction with external sources.
CP monitoring techniques: potential, potential swing, bond currents
measurement with swain spools.
Special Ultrasonic Inspection. See Methodology of Inspection
Potential risks for stray current corrosion can be identified by
CP monitoring.
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
SSC
Sulphide Stress Corrosion Cracking
Description
Susceptible
Materials
Cracking of metal under the combined action of residual and/or applied
tensile stress, corrosion in the presence of water and hydrogen sulphide,
and a susceptible microstructure. SSC involves hydrogen embrittlement
of the metal by atomic hydrogen that is produced by the sulphide
corrosion process on the metal surface, or by cathodic over-protection or
welding. The atomic hydrogen can diffuse into the metal and produce
embrittlement, drastically reducing ductility and deformability and
increasing the likelihood of cracking. Depending on stress level and
environment the onset of cracking can be rapid and catastrophic.
Carbon steels, low alloys steels, stainless steels and non-ferrous metals
such as Ni-based and Ti Alloys (also Co-based, Al, & Cu alloys)
Variables
Temperature
Pressure
Chlorides/
Oxidants
SSC is temperature dependent. For carbon and alloy steel
susceptibility to SSC decreases above 65°C depending on tensile
strength (refer ISO 15156-2). Duplex stainless steel is most
susceptible to SSC between 60 and 100°C.
Susceptibility to SSC increases with increasing partial pressure of
H2S above 3.5 mbar (0.05 psi) for carbon and low alloy steels.
The threshold level is lower for martensitic, austenitic and duplex
stainless steels.
The presence of chlorides, free sulphur or other oxidants can
significantly increase the susceptibility to SSC. Stainless steels
are particularly sensitive to chloride concentration.
pH
Hardness
Stress
Location
Carbon steels that have a bulk hardness of maximum 22 HRC
(Hv 248) do not commonly suffer from SSC. Higher hardnesses
may be permissible for alloy steels (refer to ISO 15156-2) and
CRA’s (refer to ISO 15156-3).
External applied stress and residual stresses such as forming and
welding operations.
SSC normally occurs at welds in hard weld deposits or heat-affected
zones but can also occur in hardened or susceptible parent material.
Morphology
The cracking is normally transgranular with cleavage regions on the
fracture surface.
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
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Corrosion Degradation Mechanisms
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
EP200703200907 – June 2008
Proper selection and specification of materials can minimise the risk of
SSC. Post weld heat treatment will also reduce the risk. SSC is unlikely
in a dehydrated environment. Effective use of H2S scavenger may reduce
the susceptibility of SSC. Raising pH or limiting H 2S partial pressure
(e.g. through relief valve setting) can also reduce the risk of SSC.
Use of coatings is not acceptable for preventing SSC. Metallic cladding
with CRA can reduce the risk of SSC.
The use of the principle of incubation time for transitory conditions should
not be used because onset of cracking can be rapid.
PT, MT, ACFM, possibly UT. See Methodology of Inspection
Tool for corrosion evaluation is not applicable. However, following
references can be used to assess the susceptibility to SSC:
1. DEP.39.01.10.11 Selection of Materials for Life Cycle Performance.
2. EP 2000-5594, Technical Support Document to DEP 39.01.10.11-Gen.
3. ISO 15156: Petroleum, petrochemical and natural gas industries Materials for use in H2S-containing environments in oil and gas
production.
4. SEPCO CRA and Steel Guide
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
UND-DEP-CR
Under Deposit Corrosion
Description
All under deposit corrosion begins with a deposit. The source of the
deposit can be un-removed mill scale from the unit installation, hematite
deposits from return condensate, or contamination from water treatment
plant upset. This process set-up the corrosion cells [D. Daniels, M & M
Engineering Newsletter, Spring 2003].
All metals whenever differential cells are created.
Susceptible
Materials
Variables
Temperature
Pressure
Flow Rate
Salt Content
Environment
Location
Higher temperature can avoid wet conditions but for certain alloys
should not higher then the chloride stress corrosion cracking
threshold temperature.
N/A
Slow flow can result in deposition of solids
The corrosion rate is higher when chloride ion concentration
increases
Attack can be more severe with the present of microorganism.
It is a potential threat wherever solids accumulate in a system
Morphology
Figure 1: Example of under deposit corrosion. [http://www.eci-ndt.com/gallery_a.htm]
Mitigation
Methodology
of Inspection
Tools for
Corrosion
Rate
Evaluations
Under deposit corrosion mechanisms include hydrogen damage,
phosphate attack and oxygen pitting. They are all grouped together
because they all manifestations of the same problem-namely the
concentration of an undesirable chemical species under a protective
coating [D. Daniels, M & M Engineering Newsletter, Spring 2003.]. Figure
1 shows example of under deposit corrosion. The materials suffer from
under deposit corrosion can experience wall thinning and pitting.
Pigging can effectively mitigate under deposit corrosion for pipelines.
Use of corrosion resistant materials. Oxygen scavenger can be used to
get of oxygen at an open system. A suitable coating and painting and CP
systems of a component can mitigate external under deposit attack. It is
also reported that chemical cleaning is one of the ways to remove
deposits but this method must be used in caution.
See Methodology of Inspection
N/A
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Table with descriptions of “Other” Degradation Mechanism (Secondary Importance to E&P)
Degradation
type
Acid
Corrosion
Code
AC-CR
AR /
NAR
AR
Mechanism
Morphology
Accelerated corrosion of alloys by
water containing a trace amount
(ppms) of hypochlorite ions added
as a biocide.
Stress corrosion cracking of
carbon steel in the presence of
alkaline water containing
carbonate and H2S.
Stress Corrosion cracking in
aqueous NaOH can occur at
elevated temperatures. Attack is
predominantly found at welds with
no stress relief / PWHT.
For carbon steel general corrosion occurs.
For stainless steels, hypochlorite can lower
the threshold temperature for the onset of
pitting and crevice corrosion.
Cracking is intergranular and occurs as a
network of fine oxide filled cracks, normally
in the base material but sometimes in the
weld metal and HAZ.
Caustic cracking leads to the formation of
intergranular cracks, which typically occur
as a network of fine cracks.
A material experiencing creep undergoes
various stages of deformation.
1st stage:- Initially, rapid extension occurs
but at a decreasing rate.
2nd stage:- Voids form at grain boundaries
perpendicular to the stress direction as
extension occurs at constant rate.
3rd stage:- Void coalescence occurs with
the formation of intercrystalline cracks as
extension accelerates leading to failure.
Localised thinning and pitting.
Carbonate
Stress
Corrosion
CARBONSCC
NAR
Caustic
(Stress
Corrosion)
Cracking
CAUSCC
NAR
Creep
CREEP
AR
The time dependent plastic
deformation of a material normally
at high temperature under the
action of a constant stress less
than the yield point.
Crevice
Corrosion
CREVICECR
AR
Localised attack of a metal within
a narrow gap or crevice in the
presence of aqueous. Differential
aeration is developed i.e. a
difference in the dissolved oxygen
content of the bulk liquid from that
present in the crevice. However,
in the case of copper alloys,
crevice corrosion can result due
to differences in the concentration
of copper ions.
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
35
Possible Locations and Remarks
In (hypochlorite treated) seawater and
cooling water systems.
There have been occurrences of external
attack of onshore pipelines.
See also the API module.
Carbon steel and low alloy ferritic steels are
susceptible at moderate temperatures.
Historically caustic embrittlement has been a
cause of boiler failure.
The NACE Corrosion Engineer’s Reference
Book gives a ‘Caustic Soda Service Chart
(2nd Ed. p.113).
Historically, creep failure of steels has
occurred in (superheated) steam service and
in chemical plants with operating
temperatures in the range 450 to 550oC.
Softer non-ferrous alloys have a lower
temperature threshold/resistance to creep.
Use of creep resistant alloys is required for
gas turbines.
Most matals are susceptible to crevice
corrosion. Even nickel alloys and titanium
alloys are not immune to this type of attack
under severe conditions.
EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Degradation
type
High
Temperature
Oxidation
Local
Overheating
Code
HTOXID
AR /
NAR
AR
Mechanism
Morphology
Degradation of a metal as a result
of reaction with oxygen at high
temperatures.
Degradation of a metal as a
consequence of (local)
overheating.
Formation of oxide scales and uniform wall
thinning. Often internal oxidation occurs
along the grain boundaries.
This often microstructural change visible
under a microscope. Local deformation
occurs if the combination of overheating
and mechanical load has led to creep or
yielding.
The cracking is most often intergranular.
Possible Locations and Remarks
For carbon steel this occurs above 450oC.
See also the API module.
OVER
HEAT
NAR
Methanol
Stress
Corrosion
Strain Aging
METH-SC
AR
Titanium and its alloys can suffer
stress corrosion in pure methanol.
STRAGING
NAR
Strain-ageing carbon steel results in
increased tensile strength and hardness. A
reduction in toughness can also occur.
Sour Water
Corrosion
ASWCR
AR
Pitting – the pits are often small but deep
as though they had been drilled, hence the
name “Black & Decker” corrosion
Can occur in water injection / disposal
systems handling sour water
Water
Hammer
WTRHAM
NAR
After cold working carbon steels
(and some other alloys), they can
undergo a change in mechanical
properties with time. These
changes occur slowly at
atmospheric temperature but may
be accelerated at higher
temperatures.
Corrosion by water, containing
H2S and oxygen. The H2S reacts
with Oxygen to form SO2, which
acts as a very effective oxidant.
Water hammer is the occurrence
of high shock loads when liquid
flow is shut off i.e. due to rapid
closure of a valve
Failures have occurred in chemical plants at
near ambient temperatures. However, the
presence of moisture inhibits attack.
Note:- The results of tensile tests of carbon
steel linepipe from ONEgas pipeline reeling
trials have shown some increase in (ultimate)
tensile strength but reduction in the yield
strength of specimens taken from the
position of maximum strain.
Water hammer can cause mechanical
damage/distortion of piping systems.
475oC
Embrittle
ment
475/885
EMB
NAR
Loss of ductility as a result of
prolonged soaking within the
temperature range 400 to 500oC.
Damage is not apparent (as for sigma
phase formation). Embrittlement may lead
to brittle fracture of stressed components.
Water hammer is preventable by correct
design of piping systems. For GRP piping,
refer to the UKOOA Spec. & RP for Use of
GRP Piping Offshore, Section 3 (Design)
para 5.3.2.
Occurs typically in steels with a chromium
content above 15% (m/m).
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
36
Gas fired firetubes of reboilers when the
external surface is heavily fouled or coked or
the reboiler is operated with a low liquid
level.
Corrosion Degradation Mechanisms
EP200703200907 – June 2008
Methodology of Inspection
Abreviations
AR – Age related (Determination of RL is possible), NAR – Non-age related (Requires monitoring), SB - Strategy Based
Definitions
On defect characterisation for determination of NDT technique and coverage:
- Wall loss:
- General - wall loss over the surface of the complete object
- Localised - wall loss limited to a specific area.
- Local pitting acc. ANSI B31G: "Corrosion damage with a longitudinal extent
not exceeding 0.5* √(D * tn), (where D is diameter). In practice this is approximately 3 * tn.
- Damage interaction acc. Shell-Fitness For Service:
Individual corrosion damage can interact if they are too close.
In general (for cylinders), if damage is separated by more than
a distance of √ (D * tn ), they can be assessed as independent sites.
For any inspection finding, specify :
- Wall loss
: General / Local
- Morphology
: Thinning / Pitting / Cracks
- Depth / Wall loss distribution
: Even / Uneven
with additional in case of Pitting : Regular / Irregular
Figure : Different types of wall loss characterisation
Note: For more information regarding inspection techniques, please contact Inspection Department.
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
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EP200703200907 – June 2008
Corrosion Degradation Mechanisms
Morphology matrix of Degradation Mechanisms in E&P
Atmospheric corrosion
AR Ext
ATCR
(x)
Carbon Dioxide Corrosion
AR
WET-CO2-CR
x
Chloride Stress Corrosion Cracking
NAR
CL-SCC
Corrosion under Insulation
SB Ext
CUI
Erosion by Sand
Erosion Corrosion
AR
ERO-SND
AR
ERO-CR
NAR
CORFAT
x
NAR
MEFAT
x
(incl. Erosion by liquids / Cavitation)
Fatigue - Corrosion Fatigue
Fatigue - Mechanical Fatigue
(incl. Vibrations)
RRM ParentFMId
OG.03.20735
Applicable
Module
S-RBI
Degradation
Library
(Near) Weld
S4 - CLSCC
3-SCC
T3A/B - CUI
6-Ext
x
T13 - EROSI
2-Thin
x
T13 - EROSI
2-Thin
x
Relate to S8
5-Mech
x
THFAT
Hydrogen embrittlement
Hydrogen Induced Cracking
(incl. Stepwise Cracking - SWC)
Liquid Metal Embrittlement
Low temperature Embrittlement
NAR
HEMB
x
NAR
HIC / SOHIC
x
NAR
LMC
(incl. Brittle Fracture /
Mechanical Overload Steel)
NAR
BRITFRACT
Microbiological Induced Corrosion
NAR
MI-CR
Organic Acid Corrosion
AR
ORG-AC-CR
x
x
Oxygen Corrosion
Polymeric Fracture
(incl. Mechanical Overload GRP)
Seawater Corrosion
AR
OX-CR
x
x
NAR
POLYFRACT
AR
SEAWTR
SENS
Sulphide Stress Corrosion Cracking
NAR
NAR
Ext
NAR
Ext
NAR
Under-deposit corrosion
AR
x
x
x
Stain
less
Stain
less
x
x
x
x
x
S8 - MEFAT
5-Mech
x
x
x
H7 - THFAT
5-Mech
x
-
2-Thin
Relate to L1 H3 & H4
4-MED
-
3-SCC
-
6-Ext
-
4-MED
-
2-Thin
-
2-Thin
-
2-Thin
-
4-MED
-
2-Thin
-
5-Mech
x
-
6-Ext
x
-
6-Ext
Relate to S1 - WHSCR
3-SCC
-
2-Thin
x
x
x
x
x
x
x
x
Stain
less
x
x
x
x
x
x
x
x
x
x
x
x
x
SSC
x
x
x
x
SOIL-CR
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
Exxternal
near surface
crack
x
Stain
less
GALVANIC
UND-DEP-CR
External
surface crack
2-Thin
NAR
STRAY CUR
External
thinning / pitting
6-Ext
-
NAR
Stray Current Corrosion
Dimension
changes
ATCOR
x
Galvanic Corrosion
Soil corrosion
Material
changes
x
x
Fatigue - Thermal Fatigue
Sensitisation
Embedded
defect
.
.
Laminations
Abbriviation DM
(Added)
Internal
surface crack
for choise of
NDT-technique,
(ref. 9.4 Failure Mode)
Internal
local pitting
Flawtype /
Failure characteristic
Internal thinning
& general pitting
(Yellow = “Secondairy DM”)
Age-related /
Non-Age-related /
Strategy Based ;
Ext: external)
Degadation Mechanism
Approach:
The matrix given below is a listing of degradation mechanisms that could occur in Hydrocarbon production and processing installations,
grouped per main Failure Characteristic. For each degradation mechanism the probable morphologies are indicated (matrix to be modified subject to experience).
x
x
x
x
x
38
AC-CR
Caustic (Stress Corrosion) Cracking
NAR
CAUSCC
x
Creep
AR
CREEP
x
Crevice Corrosion
AR
CREVICE-CR
High Temperature Oxidation
AR Ext
HTOXID
Local Overheating
NAR
OVERHEAT
Methanol Stress Corrosion
NAR
METH-SC
x
x
x
x
x
AR
ASWCR
NAR
STR-AGING
Water Hammer
NAR
WTR-HAM
x
400 to 500°C Embrittlement
NAR
475/885 EMB
x
5-Mech
x
-
2-Thin
x
T11 - HTOXI
6-Ext
-
4-MED
-
3-SCC
x
x
x
x
39
RRM ParentFMId
H2-Thin - CREEP
x
x
x
OG.03.20735
2-Thin
3-SCC
Tita
nium
Strain Aging
Applicable
Module
S-RBI
Degradation
Library
T4 - HCLAC
S2-Thin - CAUCR
x
x
x
(Near) Weld
Exxternal
near surface
crack
External
surface crack
External
thinning / pitting
x
Sour Water Corrosion
EPE Library of Corrosion Degradation Mechanisms EP200703200907.doc
Dimension
changes
Stain
less
AR
Material
changes
x
Acid corrosion
Embedded
defect
.
.
Laminations
Abbriviation DM
(Added)
Internal
local pitting
for choise of
NDT-technique,
(ref. 9.4 Failure Mode)
Internal thinning
& general pitting
Age-related /
Non-Age-related /
Strategy Based ;
Ext: external)
(Yellow = “Secondairy DM”)
Approach:
Degadation Mechanism
Flawtype /
Failure characteristic
Internal
surface crack
EP200703200907 – June 2008
Corrosion Degradation Mechanisms
x
x
x
SWCOR
2-Thin
-
4-MED
-
5-Mech
H3 - HTEMB
4-MED