Damage

Description Affecting Materials Temperature range Effects/Critical factors Affectfing equpt Appearnace Inspection Prevention Related Mechanisms
Mechanism

1. Localized Caustic corossion (Caustic Gouging)

in steam generation unit and Caustic added to
Crude Unit.
Regeneration of Demineralizers, Acid Neutralization, 2. Accelarated Localized Corossion in caustic
Localized and General Corossion CS, LAS, 400 SS 160F To 200F, General Corossion in high
temperature, Caustic beocme concentrated, Contaminents not effectivly mixed in oil streams.
temperature above 170 F
like chlorides and Hypochlorides, heat trace. 3. Caustic corossion in unit sthat uses
caustic to remove sulfur compounds from
process streams. 4. Heat traced
tank for caustic storage

If caustic (NaOH/KOH) is present,

1. Added to BFW, and enter during regeneration of In Steam generating system, Caustic corossion
demineralizers. Localized Caustic Corossion (Caustic Gouging) is is prevented by
Caustic Gouging is localized metal loss
2. Added to Process stream for Acid Neutralization or associate with boiler and steam generating General Corossion - UT Straight beam or UT 1. Proper Design. 2. By
appear as groove in boiler tube and
reactant to remove sulfur or chlorides. equipment including HX. Also occurs in Steam Scanning or other similar technique to measure wall Amount of free caustic, adequate water
locally thinned area under insulating
CS, Low alloy Steel and 400 SS 3. Alkaline solutions or salt enter to process generating Equipmet in H2 manifaturing unit thickness flooding and water flow by proper brner
deposits.
stream through leaks in condensor or equipment. and other processing unit. management to minimize hot spots & ingress
4. Concentrated Caustic handeled in of alkaline producing salts.
CS is most commonly used Eqquipment used to feeding to BFW or process streams.
materials, where caustic is concern.
Localized corossion due to concentration of
caustic such as Sodium Hydroxide, Potassium Localized Corossion - Manual UT including UT
hydroxide - NaoH, KOH and corossive salts, Caustic injection facilities allow proper mixing
Deposits will fill corroded depressions Scaning, AUT. Angle beam (SWUT, PAUT) or TOFD to
occurs under high evaporation or high heat and adequate dilution of caustic to avoid
and mask damage below. determine the extent of localized corossion. RT can
transfer condition. caustic on hot surface.
be also used within the technique.

Approximate temp range of 160F To Localized gouging in waterline where

200F, depend on concentration. corossive concentrate. 1.
In vertical tubes, it may appear as CS & SS have serious corossion problems in
Caustic Corossion In high solution strength caustic, Temp above 170 F, cause Casutic corossion occurs in Caustic added to circumfrential groove. Permanently mounted thickenss monitoring sensors high strength caustic at elevated temp. Alloy
General Corossion in high temperature general corossion in CS Crude Unit Feed. 2. In Horizontal or slopped tubes , 400 & nickel based alloys have lower corossion
above 170 F Grooves appears at top of tube or rates.
Longitudinal or Longitudinal grooves on
opposite side of tubes.
300 series SS is resistant to caustic
corossion untill Pasivity is damaged.
For Localized caustic gouging, buildup the caustic strength
or salt concentration.
Caustic corossion of CS at Elevated
1. Caustic become Concentrrated by Depature from Accelerated Localized Corossion occurs in Pre
temp is generalized corossion but Heat or steam tracing can cause localized corossion
Nucleate Boiling (DNB), evaporation and decomposition of heat HX, Farnace tubes, transfer lines if caustic
confined to the location of high due to high temperature and improper installation.
salts. is not efffectivly mixed with oil stream.
Temperature. Ex: Next to Heat Tracing.
2. High temperature increase the corositivity of solution,
It also occur in general thinning at elevated that increase the corosion rate.
Temperature depend on alkali and caustic
solution strength. Contaminents like Chlorides and Hypochlorides increase the Units using caustic to remove sulfur from Caustic injection sites shall be examined as per API
corossion rate. process streams. 570 & API 574
300 series SS is suspecable to
Caustic corossion at elevated Heat Traced tank for caustic storage and
temperature. Internal Access is not available, (For tubing, very
Heat trace can cause the corossion problem. Cautstic feed near process injection will cause
small dia equip) VT by Boroscopic inspection.
caustic corossion, if temperature is too high.

CSCC occurs parallel to weld in adjacent

CSCC by Sodium Hydroxide and potassium hydroxide (NaoH, Caustic Handling Equip in H2S, Mercaptan
to base metal (Highest welding stress),
KOH) Caustic soda & Caustic Potash is fuction of Caustic removal units, Equip use caustic for also occurs in Weld Deposit, HAZ &
Strength, Metal Temperature and Stress level. Neutralization in sulfuric acid alkylation units Effectivly preveted by PWHT at 1150 F, with mini
Transverse to weld.
and HF Alkylation unit. Caustic injected into holding time as 1 Hr. Same for Weld repairs &
feed to crude tower for Chloride control. internal/External attachments.

Increasing Caustic Concentration and Temperature, that

increase probability and rate of cracking. Conditions like to
Surface initiated Crack, exposed to caustic occur cracking identified by Plant Experience and In contaminated Caustic solutions, stress relive even
(Alkaline Hydroxide solutions) at elevaed CS, ALS, 300 SS are suspectable. Recommended Operating Limit for CS in Caustic Service. at low / safe temp as Recommended operating
temperature, is adjacent to Non-PWHT welds. limits for CS in caustic service.
Crack pattern is Spider Web of small
Failure occurs in improperly Heat Traced equip cracks that initiate at or interconnect WFMT, ACFM, ECT to detect Surface Breaking cracks. 300S SS is little advantage of resistance to
cracking in CS
and Heating coils & Heat Transfer Equipment. with wle related flaws.

Cracking occur att Low caustic level, if concentrating Nickel Based alloys are more resistant to CSCC,
Failure in equip, as result of steam cleaning, SWUT, PAUT to detect/Size cracks and used to
mechanism is present. Caustic concentration 50 PPM to 100 Cracks confirmed thru Metallographic monitor the crack growth. at High Temp and caustic concentration. But
after being in caustic service.
PPM to sufficient to have caustic cracking. Examination. Cracks are branched & formation of Molten caustic in absence of free
Intergrannular. Appears as Network of water at high Temp as 604 F, is called Molten
fine cracks & Oxide filled cracks. Caustic Cracking.
CSCC is form of ASCC DSS is suspectable but improved
Caustic Stress resistance when compared to 300 SS
corossion cracking Residual Stress from welding (Non-PWHT welds) or Cold In 300S SS, Cracks are Transgranular,
Working (Bending or Forming) cause cracking, will lead to but can be intergranular for Non- PT/MT can be Not effective to find tight crack,
CSCC. Applied Stress (From Pressure or Mechanical loading) Trace of caustic become concentrated in BFW sensitized SS. If Transgranular, is cracks are oxide filled. RT is Not effective in
also cause CSCC. But it is uncommon, that applied stress is and can result caustic SCC of boiler tubes that difficult to distinguish from CL SCC. detecting fine/tight cracks. Steam out of Non-PWHT CS is avoided. Equip
lower than yield point and residual stress. alternate between wet and dry condition due CSCC produce Black Magnetitie layer shall be water washed before steam out and
to overfiring. Also occurs in superheater due to (Oxide layer) on crack surface. But CL low pressure steam used for short time to
steamdrum carryover. SCC not produce oxide layer. minimize exposure.

Proper Design & Operation of Injection system

Thermal Stress relief (PWHT) is effective in preventing CSCC. AET -- locate and monitor the crack growth. to ensure Caustic is properly dispersed before
entering to high temperature system.

Crack Propagate rate increase with Temperature and grow CSCC of Nickel Based Alloys are Soda Ash (Sodium Carbonate) used as
thru wall in matter of Hours in concentrated caustic or observed as either Integranular or Severe crack identified by visually. Protectvice measures against Polythionic Acid
conditions promote caustic concentration. Caustic Craqcking in boiler at roled tube joints, due to Transgranular. Stress Corossion Cracking in 300 S SS.
concentration occures due to Alternating wet/dry caustic concentrating between Tube and
conditions, localized hot spots and High Temp Steam Out. Tubesheet.
Spcial Care about Steam Tracing design and Steam out of
Non-PWHT welds.

Nickel based alloy is more resistant. Crack occurs at unintended carryover of caustic
Contaminents in casutic like sulfids increase likelihood of
into equipment, was not designed to handle
CSCC.
hot caustic (Not Stress releived) such as steam
condensate piping

Chloride crack may be either Process side or

Material of Construction which is resistant to Cl
Critical Factore: Chloride content, temp, Tensile stress, PH, Non- Stress relieved SS in any proces unit Surface breaking cracK in process side external, under insulation that become wet
SCC should be used. CS, LAY, 400S are not
All 300S SS is highly suspectable. presence of O2 and alloy composition. suspect to CL SCC. Process side will not cause or externally under insulation. condition. It should be underatnd to develop proper
suspectable to Cl SCC
Surface initiated crack of 300S, nickel based Welds of 300S SS contain some SCC, but operates above 140 F andexposed to inspection scope.
alloys by combined action of tensile stress, ferrite, produce Duplex Structure, is alternative wet & dry conditions on outside.
Temp and aquous chloride environment. more resistant to CL SCC than base
metal. Cl SCC cause by Inorganic Cl ions (Cl-). Organic Cl ions not
No visible sign of weaR 1. VT to find advanced stages of cracking In hydrotest, Low chloride content water shall
directly cause Cl SCC but they produce ionic or inorganic Cl-
be used, and followed by thorough dryout.
ions by hydrolysis process or thermal de composition. So In water cooled condenser and process side of
orgnanic chlorides will leads to Cl- SCC crude tower overhead condenser.

Cracks normally occurs above 140 F and

experience shown in temp limit Suitable Coating shall be applied to SS, pirior to
guidance for fixed eqip. Increase Chloride level, increse probility of cracking. 1. SS in hydroprocessing unit is suspectable to
No practical limits of chloride is exists becsaue of potential crack particularly during startup, if not properly Crack with many branch, Spider Web, insulating. 1. Shrink wrapped PVC lables,
for chloride. Heat transfer condition in surface of exchanger purged. Craze cracking on surface coating, label adhesive with high level of
tubes increase potential for cracking. chlorides or other halogen shall be avoided.
2. Non- condensing 2. PT used for Cl SCC. Extremly fine crack difficult to
DSS is more resistant but still system will be paritcular concren, because Chloride content find by PT. Special surface preparation like polishing,
Also refered as Chloride Cracking suspectable cannot be removed by water phase. high pressure water blasting may require.

Increasing Temp increase potential for cracking, as long as Bellow & Instrument tubing associated with
the other elements (Stress and aquous chloride solution) are hydrogen recycle streams contaminated with
present concurrently. Although exeptions at low temp and chlorides.
Chloride stress ambient temp, Cl SCC occurs above 140 F and expeirnce Metallograohy shows branced and 3. ECT used in Condenser tubes as well as piping and Avoid design that create stagnant region where
corossion cracking shown in temperature limit guideline for fixed equip. Transgranular cracks. pressure vessel chlorides can deposit or concentrate.

4. Angle beam UT (SWUT, PAUT) from opposite wall Not std/common that high temp stress relief of
used to detect crack detection. Detection and 300S Series after fabrication wil reduce
Cracking potential increase at lower PH. However crack will In boiler drain lines Characterization of crackis difficult due to craze residual stress. Consider possible effects of
not occur PH below 2. At these lower PH, general corossion cracked and multi branched appearance of Cl SCC. Sensitization suspectable to PTA SCC, distortion
Nickel Based Alloy is highly resistant Operating temp range of Extenral CL occurs. SS and some nickel based alloys can suffer from problems and potential for stress relaxation
but not immune SCC is 140F to 400F Caustic SCC in alkaline environment. In Sensitized 300S SS in intergranular cracking.

Applied stress or tensile stress. Most common area of

concern is Non-PWHTS welds. High stress componenets, External Cl SCC on insulated 300S SS, if Avoid HX with 300S SS and high delta T
Cold work such as Expansion bellows are highly ssupected insulation gets wet. Operating raange of Cl SCC in Nickel based alloys on severe between shell and tube, where localized
for cracking Extenrla CL SCC is 140F to 400F conditrion is same as CL SCC in SS 5. RT is sensitive enough to detect crack. ocnsideration occur in tubes.
Highly localized CL SCC in tube bundles of HX,
O2 Dissolved in H2O accelarates SCC. Other oxidizers (Co, wher fluid temp inside tubes is above dew Avoid High chloride run off, that can occur with
CO2) inaddition to O2 also enhance Cl SCC. point. Fracture surface has brittle appearance snow and ice melting

Nickel Content -- major effect on resisitance. Nickel content

about 8 % to 12 % has greatest suspectability of Cl SCC.
1. Alloy
content above 35% of nickel has high resistant 2. Above
40% of Nickel nearly immune but cracking occurs still in Unit provessing Bio Based or renewable
severe conditions. 3. Low Nickel SS feedstock is suspectablt to CL SCC, due to high
such as DSS have improved resistance over 300S SS, but level of organic chlorides convert to inorganic
not immune. chlorides.

Manual UT Grids or Automated scans to determine

Wide range of metal loss:
the extent of erosion. Change in shape, Geometry and Materials will
All Equip exposed to moving fluids and Catalyst Localized loss in thciknes sin form of
All metals but mostly CS and Copper Mechanical erosion and Metal loss rate is depends on mitigate erosion and Erosion-corossion.
Metal Loss by flowing the solid prticles alone or is subject to erosion and Erosion- Corossion. grooves, gullies, waves, rounded holes,
alloys Velocity and No of Impacting Particles, Size, shape, hardness Change in Direction, change in Diameter, More
solid/liquid stream physically Abrading the Piping bends, Elbows, Tees, reducers, valleys or greater amount of thinning in
and Density of impacting particles, Hardness of material is turbulant areas. Increasing Dia will reduce velocity
material to metal loss flow of corossive liquid or Downstream of Letdown valves, pumps, localized area like outer radius of
Refractories also affected subject to erosion and angle of impact. Streamlining bends to reduce impingment and
vapor comibned with its velocity assisted to blowers, Properllers, implers, agitators. Elbow, exhibit in directional pattern.
Random Placed Point UT is not effective, if they are replaceable Impingment baffles.
removal of Protective film or scale.
not placed in potential suspectable areas.

Improve resistance to erosion by increasing

hardness.
1. Softer Alloys like Copper , Aluminium easily subject to
Hydroprocessing reactor subjected to erosion- Liquid lines contain particulates, low
Mechanical damage, severe metal loss by High Velocity. Profile RT used to detect area of erosion, but not
corossion by Amonium Bi Sulfide. Metal loss velocities < 5 fps (1.5m/s) alow solid Using Harder Alloy, Hardfacing, surface
determine actual remaining wall thickness. UT
depends on Conecentration of Amonium Bi tumble to bottom, cause erosion or hardening Treatment.
2. Increasing hardness of Eroding metal component, can Thcikness test to quantiy wall thickness.
Sulfide, H2S and NH3. Erosion-corossion at 6 O Clk position.
reduce the rate of erosion.
Erosion resistant refractories in cyclones and
Slide Valves is successfully Resisted erosion.
Erosion : Mechanical Removeal of surface
Materials without True Passivity,
material as relative movement between Solid,
Corossion rate is limited by
Liquid, Vapour and their combination, is found
protective corossion layer or
in Solid entrained in liquid or vapour stream Best mitigation for Erosion-Corossion
inhibitive film
such as Slurry or fluidized solid.
GWT as Screening Technique - Change in direction
Erosion/Corrosion By more corossion- resistant alloys and altering
wil not impede effectiveness of inspection.
Solid entrained in Liquid also has corossion component. Crude and Vaccum Unit exposed to Naphthenic process environment to reduce corositivity.
Solid particles remove protective scales/Barrier on metal acid is suffer by Erosion-Corossion Metal loss Failure occur in relativly short time
surface. Rate of metal loss is greater than Corossion depends on temperature, Velocity, Sulfur Example: Deaeration, condensate injection and
Mechanism alone. content and naphthenic acid content. Addition of inhibitors.
Permanently mounted thickness monitoring
sensors.
Increasing Hardness alone will not improve the
resistance.

With Exception of water droplets in steam

system, it is unlikly that any flowing liquid or Liquid Droplets in Vapour, metal loss depends on Velocity,
liquid impingment (Without solid) able to erode Droplets and Corositivity of liquid.
the material of construction without corossion
component present. Increasing the pipe thickness, that decreases the ID and Heat Exchanger utilize Impingment plates and
Erosion- Corossion is commmon in alkylation Infrared Thermography scan used to detect
increase the Velocity that leads to increase the corossion Tube Ferrules to minimize the erosion-
unit. Refractory Degradation.
Same above for Gas, with possible execption of rate. corossion problems.
steam cutting
Erosion-Corossion : Damage that occurs when
More corossive the environment, greater will be erosion- Specilized Coupans used to determine if erosion is
particle erosion and high flow velocity
corossion, erosion effect damages the stability of protective potential concern.
contributes for corossion by removing Boiler water circuit suffer corossion by high
film, scale and other barrier, depends on corossion
protective films or scales and Accelarate velocuty flow known as Flow Accelerated
resistance. Factor that increase corositivity environment,
corossion rate. corossion.
such as temperature and PH, increase suspectability of Sampling of process stream for chemical analysis to
eroson-corossion metal loss. determine erosion in system.
Is also called Velocity Assised Corossion

In refinery, Erosion- Corossion Situations,

Corossion is Dominent

3 conditions:
Best Method of prevention or mitigation is
Good Design.
1. Two different metal with two different electrochemical
Any unit where different material are coupled
potentials. VT and UT Thickness guaging is effetive method for
in conductive fluid. Coupling of different material in conductive
detecting galvanic corossion.
fluid sahll be avoided.
2. Dissimilar metals are electircally coupled together, either
HX are suspected, if tube material are different If two different materials are welded,
direct contact or connected by wire or other conductor. One 1. VT indicates loss of anodic material by displaying
from tubesheet and buffles, particularly if bolted or rolled connections. Coating can be used to mitigate the corossion
of them is Anode and other is Cathode. oxidized material.
saltwater cooling is used. of galvanic couple.
3. Both metals must be immersed or in contact with same 2. Ut Thiness measurement.
continuous electrolyte ie: Fluid can conduct elecric current.
Moisture or water phase is required for fluid to have enough
conductivity.

More active material suffer by

More Noble material (Cathode) is protected by active generalized metal loss and more
Burried piping and ship hulls are typical Permanently mounted thickness monitoring
material (anode). Anode corrode higher rate, when it is not aggeressive localized metal loss in
location for galvanic corossion. sensors.
conneced with Cathode. adjacent to point of connection, as
Zinc to steel, anode to cathode Crevice, grooving, pitting corossion,
At junction of dissimilar metal joint together in
Galvanic Corossion All metal execption of most noble relationship appears to reverse in
suitable electrolyte, such as moist, aqueous
metals. aerated water at temperature above
environment or soil containing moisture.
150F. Amount of surface area exposed to eectorlyte between
more active anode and more noble cathode material has
signifficient effect. Damage hidden in underneath the bolt and rivet
head. In piping, Specially designed Elecric insulating
1. If small anode to cathode surface area ratio, Corossion bolt sleeves and gaskets can elliminate the
rate of anode is very high. An angled beam technique is used to eveluate electric coupling.
hidden loss under the head of fastners.
2. If large Anode to Cathode surface area ratio, Corossion
rate of anode is less.

Same metal act as either anode or cathode in different

Sacrificial anode are installed in HX to control
situation due to effect of surface film, scale and properties
channel and tubesheet corossion.
of electrolyte.

Same electrochemical coupling of diferent material leads to

galvanic corossion, it put the beneficial effect in form of
cathodic protection when more active material is coupled
with less active material (Aluminum or magnesium coupled
with carbon).

Zinc to steel, anode to cathode relationship appears to

reverse in aeraed water at temp above 150F.

Crude Unit:

1. Optimizing crude oil tank, water separation

HCL Corossion is General or localized and most and withdrawal and crude desalting operation
severe in most common material of construction. to reduce the chloride content in feed to crude
tower. Common target is 20 PPM or fewer
1. VT for accessable components, characterized by chlorides in overhead water accumulator.
Orange- Yellow discoloration with scale buildup.
Aquous HCL causes both general and localized Severity of corossion increase with Found in seveal units expecially in crude, CS & LAS suffer by uniform corossion, 2. Upgrade CS to Nickel or Titanium based
All common materials of Critical factors: HCL Acid concentration, Temperature and
corossion and is very aggressive to most increase in temperature and increase vacuum, hydroprocessing unit and catalytic localized corossion and Under deposit 2. UTT and AUT to determine extend of localized based alloys to reduce HCL problems.
construction used in refineries alloy composition.
common materials of construction. HCL Concentration. reformer unit. attack. thicnning.
3. Water wash is added to quench overhead
3. RT to find localized thinning. RT for transition stream and help to dilute HCL acid.
components (Elbow, 3 way, 4 way fittings, deadlegs)
4. Caustic injection downstream of desalter to
reduce HCl going overhead.

5. Ammonia, Neutralizing amines, filming

amines are injected in atmospheric tower.

Crude:
4. Strategically placed corossion probes or corossion
Damage in refineries is associated with dew
1. In atmospheric tower overhead system, coupons provide rate and extend of damage.
point corossion in which water vapour Aquous HCL form beneath ammonium chloride deposits and
corossion by first water droplets condense
containing water and hydrogen chloride amine hydrochloride deposits. These deposits absorb water 300S SS and 400S SS suffer by pitting
from water vapour at top of the tower. This 5. Permanently mounted thcikness monitoring 6. Well maintained process monitoring
condense from overheated steam of distillation, from process stream and injected water wash. attack.
water droplet have very low Ph and can have sensors. locations as Measuring chloride content, water
fractionation, stripping tower.
high corossion rate. and chemical injection rates is important to
Hydrogen chloride gas is not corossive in dry situation and 300S SS may experience CLSCC, if
6. PH pf water in boot of atmospheric tower manage HCL Corossion.
First water drop let condense can be highly become very corossive when water available to form temperature is high.
overhead accumulator shall be check regularly.
acidic (Low PH) and promote high corossion Hydrochloric acid.
2. HCL corossion have problem in Vacuum
rate.
ejector and condensing equipment off top of Chloride and iron content shall check less frequent.
vacuum tower.

Hydrochloric Acid Severity of corossion increase with increase in temperature

Corossion and increase HCL Concentration.

Hydroprocessing:
Hydroprocessing Unit:
1. Carryover of water and chloride salts and
1. Chloride enter unit as organic or inorganic
Neutralizing amine hydrochloride salts should
chloride in hydrocarbon feed or with recycle
CS and LAS have excessive corossion, if HCL acid produce PH me minimized.
Hydrogen and react to form HCL.
below 4.5.
2. HCL in H2 streams shall minimized.
2. Amonium chloride salts can form in various
300S SS and 400S SS is not fully corossive resistant to any
part of unit, because both NH3 and HCL is
HCL Concentration and any temperature. 3. Corossion resistant nickel based alloy should
present and they condense with waer.
be used, if necessary.
3. HCL containing in streams will cause Acid
4. Well maintained process monitoring
dew point corossion at mixing point.
locations.

Alloy 400, Titanium and Nickel based alloy is good resistance

to Dilute HCL

Catalytic reforming:

1. Same as Hydroprocessing, water washing

hydrocarbon stream used to remove highly
Catalytic reforming unit: water soluble chlorides. Special care in design
Presence of oxidizing agent (Oxygen, ferric and cupric) and operation of equipment is needed.
increase corrosion rate particularly in Alloy 400 and 1. Chlorides may stripped from catalyst and Minimizing water and oxygenates in feed will
Alloy B-2. react to form HCL. reduce stripping of chlorides from catalyst.

Titanium perfroms well oxidizing condition but rapidly fails 2. HCL containing vapour, that will result in 2. Special adsorbents in chloride beds and
in dry HCL service. corossion at mixing point, where HCL containng chloride treaters to remove chlorides from
vapour stream will mix with process stream. recycle hydrogen streams and liquid
hydrocarbon streams.

3. Well maintained process monitoring

locations.

In High Cycle fatigue, Time required to initiate and grow A. Piping and other Fixed Equipment:
Factors to determine Mechanical fatigue: Geometry, Stress level, the crack is significantly identable by NDE methods, can
No of cycle and Mechanical Properties (Strenght, Hardness and be majority of fatigue life, Detection before cracking 1. Best Defense against Fatigue cracking: Good
Microstructure) Damage is in form of Crack from high stress occurs and failure is difficult. Design help to minimize stress concentration of
Mechanical degradation by cyclic stress for All Alloy subjected to mechanical 1. Socket weld, small bore piping associated with concentration point or discountinuity such component in cyclic service.
extended period. fatigue cracking. Amplitude and frequency of vibrations (Stress level and No of pump, compressor, rotating and reciprocating as thread, a weld or corner of keyway in
cycle) in vibrating equipment such as Piping are Critical factor. pump are not fully gusseted and supported. shaft. Impractical to relay on NDE to avoid fatigue failure crack.
2. By proper design and properly placed support
Probability of cracking if input vibrational load is synchoronous Frequent NDE at specific or known problem area to find and vibration dampening equipment.
with natural or harmonic frequency of component. the crack before failure, but NOT considered as effective
and long term approach to manage problem. Material upgrade is not solution.

1. PT to detect crack open to surface.

Design Factors: Fatigue crack initiate at Notches or stress risers
under cyclic loading. Install gussets or stiffeners on small bore
2. MT and WFMT to detect crack open to surface or near connections, cannot move independently of larger
Design of component is important factor to determine surface. pipe or other component.
component resistance to fatigue cracking. 2. Small Branch Connected with unsupported Signature mark of fatigue failure : "Clam-
Surface features initiate fatigue cracks, because they act as stress valves may see vibration from adjacent equipment shell type" fingure print has concentric ring
called beach marks. 3. Angle beam (SWUT or PAUT) to detect fatigue cracks
concentration as,, or wind. at known or suspected area. Vortex Shedding minimized at outlet of control
1. Key hole of drive shaft of rotating equipment. EX: At stress concentration and welded connections, valve and safety valve by Proper side branch sizing
Ex: Dynamic loading due to Vibration, Water Stress level and No of cycle is necessary 2. Mechanical Notchs (Sharp corners or grovges). Signature pattern result from waves of crack is in internal, initiate at internal and not visible and flow stabilization techniques.
Hammer, Unstable fluid flow, Sudden and to cause failure, that may varies based 3. Weld joint flaws or mismatch. For small components, resonance also produce crack propagation during cycle above outside.
Unexpected thru wall cracking. on material 4. Tool Marking. cyclic loading and taken to consideration during threshold loading.
5. Grind marking. design and reviewed for potential problems. Compression Wave UT is needed for Very thick
6. Lips on drilled hole. Thses concentric cracks continue to components. Vibration effect is shifted to Anchored portion.
7. Thread Root Notch. propagate unitll cross sectional area to Special studies before anchored or dampeners are
8. Corossion 3. Safety Relief valve, subject to chatter, premature reduced to point where failure due to provided unless remove the vibration source.
pop off, fretting and failure to operate properly. tensile overload occurs. 4. Compression wave UT to detect crack in Bolts.
[Key Hole of shaft, Lips on drilled hole, Mechanical Notch, Good fitup and smooth transition of weld. Use
Thread Root Notch, Tool Marking, Grind Marking, flaws & 5. Vibration monitor of rotating equipment provide gradual bore tapper for different pipe schdules.
Mismatch and corossion] online detection of condition, which is shaft failure due
to out of balance condition.

Metallurical issue and Microstructre: Visual Inspection: Piping oscillation, Vibration, Water
hammering, where the small bore connection is not
Stress by Mechanical loading or Thermal loading is Materials like Titanium, CS, LAS have Endurance Limit. 4. High Pressure drop control valve, Steam reducing Crack nucleating from surface stress supported. Minimize weld defect, that can accelerate fatigue
Mechanical Fatigue below yield strength of material. concentration or defect will result in single
(Including Vibration- No of cycle increase with decreasing in stress amplitude untill the station casue vibration problem. fingerprint "Clam shell" crack.
Induced Fatigue) stress amplitude endurance limit is below in which fatigue Focus on weld joints and locations, where the pipe is
cracking will not occur, regardless of no of cycle. fixed and prevent from moving.

Effect of Mechanical loading focus on Mechanical For alloys with Endurance limit: Correlation (Mutual relationship) Minimize grind marks, Nicks, gouges on component
fatigue section. between UTS and minimum stress amplitude necessary to initiate 5. Rotating shaft on centrifugal pump and surface, which is subjected to cyclic loading.
fatigue cracking. Ie Endurance limit. compressor have stress due to change in radii and Pipe supports and spring hangers shall checked.
Effect of Themal loading focus on Thermal fatigue. keyways.
Ratio of endurance limit to UTS is between 0.4 to 0.5 Use low stress stamp and Marking tools.

Crack from B.Rotating equipment:

300S SS, 400S SS, Aluminum and other non-ferrous alloys have 1. Cyclical overstresses of component Audible sound of vibration from components like control 1. Allow for generous radius along edges and
corners in shaft Keyways.
fatigue charactristic, but does not exhibit endurance limit. without one significient, valves, is indication of fatigue cracks.
6. HX Tubes suspected to Vertex Shedding
Which means fatigue fracture by cyclic loading, regardless of 2. Isolated stress concentration point,
stress amplitude. result in fatigue failure with multiple point 2. Remove Burrs and lips caused by machining.
of nucleation and hence "multiple Clam
Maximum cyclic stress amplitude for design is selected by shell fingerpoints".
determining cyclic stress necessary to cause fracture in no of 7. Pressure swing absorber in H2 Purification unit.
cycles the component need to withstand in its life time. Typically These multiple nucleation site called as Damaged Insulating Jacketing is indicative of extensive 3. Fatigue cracking problems are addressed by
as 10^6 to 10^7 cycles. "Ratchet Marking" as reuslt of vibration. design and febrication improvements, so ensure
miucroscopic yielding when component is that metal selected has fatigue life is sufficient for
momentally cycled above its yield strength. intended cyclic service.

Endurance Limit applies to Smooth bars and similar configuration

found in Pump Shaft. 8. Transient condition (Startup, Startdown, upsets) API 579-1 /ASME FFS-1 has information to
For welded components such as Piping and others as can create intermittent, but severe vibrating determine Critical fatigue crack size and assessing
discountinuties, flaws, high stree concentration exist…...... Will condition. crack growth rate.
eliminatres the existance of endurance limit.

Inclusions found in Metal will accelerate the effect of Fatigue

cracking.

Heat Treatment also have an effect on fatigue resistance of

metal.
Heat Treatment such as Quenching and Tempering can improve
fatigue resistance of CS and LAS.

In general, finer grained microstructures tend to perform better

than coarse grained.

All iron based materials as Depends on service conditions,

Corrosion of CS or other alloys by reacting with Thinning measured by UT or RT.
Critical Factors: Chemical composition of metals, corossion is in form of Uniform
sulfur compounds in high temperature. Sulfidation occurs in high temperature
CS, LAS, 400S SS, 300S SS temperature, concentration of sulfur compounds. thinning, Resistance for sulfidation: By upgrading to
environment, where sulfur containing Liquid, Thinning in large vessel or pipe, where internal
higher chromium steels as 9Cr-1Mo
Corossion in presence of hydrogen is High Vapour or mixed stream. inspection is possible, is inspected by Internal VT
Inorder from most suspectablt to Flow conditions also affect the rate of damage. also occur as localized corrosion and
Temperature H2/H2S Corossion. and followed by UT.
Less suspectable. high velocity erosion-corrosion damage.

Resistance of iron based and nickel based alloy is

determined by chromium content.
Piping constructed form solid and clad
In Uniform thinning morphalogy,
Above 1193F, Alloy with high nickel Increasing chromium content, increase resistance of (Overlaid) 300S provide resistance to
amount of thinning is varies at different
Nickel based alloy affected to content, will suffer by sulfidation and sulfidation. Permanently mounted thickness monitoring corossion.
Crude, Vacuum, FCC, Coker, visbreaker unit location, along the length of running
varying degrees, depends on metal loss by formation of nickel sensors.
and feed section of hydroprocessing unit, pipe.
composition, especially chromium sulfides beneath metal surface, is 300S SS such as, 304, 316,321,347 is highly resistant, in high
Sulfidation refer to high temperature sulfidic upstream of hydrogen injection,
content. referes as Hot corossion. temperature sulfidation process environment. Thinning in heater tubes is monitor by UT or smart 400S SS cladding shall provide improvement on
environment, without hydrogen, is also known
pigging. resistance over CS.
as sulfidic corossion. commonly process high temperature sulfur Difference in thinning between low Si
Nickel based alloys similar to SS, with similar chrominum
containing stream without intentially added (less than 0.10%) and high Si ( greater
Suspectability of Sulfidation increase For operation above 1193F, sulfidation level, provide similar resistance to sulfidation. Smart Pigging provide more coverage than spot UT
hydrogen. than equal to 0.10%) is large, with
with increase in Nickel content. of higher Nickel content alloy can be and find thinning missed by spot UT. 400S SS is not selected for piping and equip,
marked step change in remaining wall
reduced by Lower Ni content alloy. Nickel alloys with little or No chromium level will have poor because of embrittlement and toughness
thickness.
resistance for sulfidation. concern.

1. Modified McConomy Curve : Showing typical effect of

temperature on high temperature sulfidation of steels and
stainless steels.
Operting temperature shall be monitored against
This curve indicate the general trends in effect of chemical
Sulfide scale will cover surface of design temperature.
composition, temperature and sulfur content on corossion Coker Unit, fabricated from higher nickel alloy Aluminium diffusion treatment of CS & LAS,
Smooth, large and uniform corrosion by Sulfidation(H2 free) of iron based alloy components.
Sulfidation, rates. such as Alloy 800H, will show higher corossion used to reduce sulfidation rate and minimize
sulfidation leads to rupture type failure rather begins at temp above 450F, but Temperature and sulfur level shall be monitored.
rate, that operating with tube metal scale formation, but will not provide the
than localized or pinhole leak. becomes practical concern above 500F. Deposits may be thin or thick depends
2. Multiple of corrossion rate based on sulfur content of temperature exceeeding 1193 F. complete protection.
on alloy, corrosiveness of system. Temperature monitored by tube skin thermocouples
process fluid.
and infrared thermography.
Sulfidation with or
without Hydrogen is Above two points, have typical effect of increasing
covered in API 939-C chromium content, temperature and sulfur content on
metal loss.

Silicon content of CS, will affect its suspectability to

Heater fired with oil, gas, coke and other
sulfidation. Proactive and Reactive MVPs (Material Verification
source of fuel affected depends on sulfur level
program) is to verify alloy verification and to check
in fuel.
CS with Si content less than 0.10% is suffer variable and alloy mixup in services, where sulfidation is
Copper based alloy form sulfide 500F, useful service temp, to focus on higher sulfidation corrossion rate than CS with silicon anticipated. Operation above 1193F, sulfidation rate of high
Both type of sulfidation, with and without
corossion product at lower inspection, monitoring and corossion content above 0.10%. nickel ally can be replaced by lower nickel
Hydrogen is covered in API 939-C It is uncommon for heaters, to fired with
temperature than carbon steel. mitigation efforts. content alloy
anything,
High Si content CS are still suspectable to sulfidation, but
API 578 : Guidance of material Verification Programs
usually low sulfer gas to meet environment
Steel with low Si content may suffer higher rate. (MVP).
restructions, especially in US.
Steel with high Si content suffer in Lower rate.

Sulfidation (H2 free) of iron based alloys begins at metal

temperature above 450F, but normally becomes particular
concern above 500F.

Experience shows that, above 500F as service temperature

which need to focus on inspection, monitoring and
corrosion mitigation efforts.

Crude oil and hydrocarbon streams contain sulfur

comopunds at various concentrations.

Sulfidation caused by H2S and reactive sulfide species

formed by thermal decomposition of sulfur compounds at
high temperatures.

By knowing "Reactive sulfur" in process stream : is key to

predict actual corrosivity based on weight % of sulfur alone.
 Wet H2S Damage

Critical Factors
Liquid water phase containing H2S (Sour environment) must present and contact the steel for wet H2S damage to occur.
Critical factor that affect and differentiate varius form of Wet H2S damage (H2S, PH, contaminents & Temperature), material properties (microstructure and hardness) and tensile stress level.
2. All DMs are absorption and premeation of hydrogen in steels.

H2S Level PH Contaminents: Temperature: Microstructure: Hardness: Tensile Stress level

H2 premeation and
diffusion rate in steel Salt and other spices in water
H2 premeation increase with found to be minimal phase, decrease PH and
increase H2S Partial pressure at 7 PH and H2 Increase corossion rate and Presence of inclusions and
due to concurrent increase in Premeation increase increasing hydrogen charging lamination, which provide
H2S concentration in water at both higher and environment and severity of Wet sites for hydrogen diffusion
phase. lower PH. H2S damage occur. and accumulation.

Value of 50 PPMW H2S in Increasing level of HCN in water phase, that increase
water phase is started as ammonia, may push corossion rate, that significantly Flat and elongated
minimum concentration, PH higher in the increase H2 premeation and manganese sulfide (MnS)
where Wet H2S damage can range, where increase the potential for all forms inclusions by ordianry steel
occur. cracking can occur. of Wet h2S damage. plate rolling practices.

Rich amine solution

is alkalimine Chemical composition and
1 PPMW of H2S in water is environment, where manufacturing methods is
sufficient to cause Hydrogen Wet H2S damage can tailored to produce HIC
charging of steel. occur. Cracks.

HIC found in SO called

Durty steels, with high level
of inclusion and internal
discontinuities from steel
H2 Premeation making process.

Blistering, HIC, SOHIC

found between ambient Blistering & HIC can develop
Hydrogen temperature and 300F or Hardness : Not related to without applied or residual stress,
Blistering higher. Blistering, HIC, SOHIC. so PWHT will not prevent.

Blistering, HIC, SOHIC

found between ambient Blistering & HIC can develop
temperature and 300F or Hardness : Not related to without applied or residual stress,
HIC higher. Blistering, HIC, SOHIC. so PWHT will not prevent.

Tensile need to cause SOHIC from

Blistering, HIC, SOHIC weld residual stresses, in absence
found between ambient of thermal stress relief. So PWHT
temperature and 300F or Hardness : Not related to is preventing and reducing SOHIC
SOHIC higher. Blistering, HIC, SOHIC. damage.

SSC is greatest About 70F

Suspectability of SSC increase and Decreases with High Local stress and Notch like
with increase in H2S partial increasing or decreasing Hardness is primary issue discontinuties such as SSC, is
SSC pressure in gas phase. temperature. with SSC. serve as inititation site of SOHIC.

CS used in refinery is not

expected to have SSC,
because of strength and
hardness is low.
Tensile stress need to cause SSC
Not suspectable to SSC in suspected material, that comes
SSC is concern below at unless localized zone from applied stress or residual
temp 200F. Hardness is above 237 HB. stress.

High Strength Steels

(Hardness greater than
22HRC) or steel hardend Hardedend steels are need to do
by welding as Cr-Mo, is PWHT to reduce hardness inorder
suscepted to SSC. to avoid SCC.
 Damage Affecting
S No Description Temperature range
Mechanism Materials

Loss of toughness due

to metallurgical 400SS, DSS, 300 600-1000
change in SS ferritic SS (Austenitic )
885 F temper phase, temp range as contain upto 10%
1 embrittlement 600 to 1000 F Ferritic phase