CORROSION MECHANISMS
MATERIAL SELECTION AND
CORROSION CONTROL
IN REFINERY
Flavio Cifà
Michele Scotto di Carlo
2
“Corrosion
is defined as the destruction or
deterioration of a material because of
reaction with its environment”
Mars G. Fontana
CONTENTS
n CORROSION AND DEGRADATION MECHANISMS
èCORROSION PROCESSES KINETIC
èLOW TEMPERATURE DEGRADATION MECHANISMS
l GENERAL CORROSION
– CO2 corrosion
– Wet hydrogen sulfide corrosion
l GALVANIC CORROSION
l PITTING CORROSION
l CREVICE CORROSION
l UNDER DEPOSIT CORROSION
l STRESS CORROSION CRACKING
– Chloride stress corrosion cracking (CSCC)
– Sulfide stress cracking (SSC)
– Alkaline stress corrosion cracking (ASCC)
– Caustic cracking
– Amine cracking
– Cracking in H2O-CO-CO 2 systems
3
CONTENTS
è LOW TEMPERATURE CORROSION MECHANISMS (CONTINUE)
l SENSITIZATION AND WELD DECAY CORROSION (INTEGRANULAR)
– Sensitization
– Weld Decay
– knife line attack
– Polythionic Acid Stress corrosion Cracking (PASSC)
l EROSION CORROSION
l MICROBIOLOGICALLY INDUCED CORROSION
l CORROSION UNDER INSULATION
l HYDROGEN DAMAGE
è HIGH TEMPERATURE CORROSION MECHANISMS
l
l
l
l
NAPHTENIC ACID CORROSION
HIGH TEMPERATURE OXIDATION
SULFIDATION
HIGH TEMPERATURE HYDROGEN DAMAGE
4
CONTENTS
n MATERIALS AND CORROSION PROTECTION
è MATERIAL SELECTION GUIDELINE
è CARBON STEEL
è LOW ALLOYED STEELS
è STAINLESS STEELS
è COPPER ALLOYS
è NICKEL ALLOYS
è TITANIUM ALLOYS
è POLIMERIC MATERIALS
è CATHODIC PROTECTION
n MATERIAL SELECTION AND CORROSION CONTROL
IN REFINERY UNITS
è DESALTER
è ATMOSPHERIC DISTILLATION UNIT
è VACUUM DISTILLATION UNIT
è AMINE UNIT
è HYDRODESULPHURIZATION UNIT
è SOUR WATER STRIPPER UNIT
5
CORROSION AND DEGRADATION
MECHANISMS
General criteria
CORROSION KINETICS
7
n STATIONARY KINETICS
Steady corrosion rate which often allows:
è corrosion rate prediction trough laboratory tests, bibliographic data
and estimation models.
è Monitoring on stream and off stream
è Upset conditions are not decisive on corrosion process
R corr
n INCUBATION PERIOD KINETICS
It presents an incubation period which closes
with high corrosion rate (cracking).
Stationary
è “upset conditions” are decisive.
Incubation period
è The incubation period may be very short (h!!!)
ti
Time
è The corrosion process once started (t > ti) continues up to the
rupture independently from the incubation conditions persistence.
• Whenever “upset conditions” are decisive for the described
corrosion mechanism they will be clearly highlighted with
UPSET
LOW/HIGH TEMPERATURE CORROSION
LOW TEMPERATURE CORROSION
n Temperature < 260°C
n Aqueous phase and presence of ionic species
HIGH TEMPERATURE CORROSION
n Temperature > 260°C
n Aqueous phase not necessary
8
CORROSION AND DEGRADATION
MECHANISMS
Low temperature corrosion mechanisms
LOW TEMPERATURE DEGRADATION MECHANISMS
n
n
n
n
n
n
n
n
n
n
n
GENERAL CORROSION
GALVANIC CORROSION
PITTING CORROSION
CREVICE CORROSION
UNDER DEPOSIT CORROSION
STRESS CORROSION CRACKING
SENSITIZATION AND WELD DECAY CORROSION
(INTEGRANULAR CORROSION)
EROSION CORROSION
MICROBIOLOGICALLY INDUCED CORROSION
CORROSION UNDER INSULATION
HYDROGEN DAMAGE
10
GENERALIZED CORROSION AT LOW TEMPERATURE
n ANODE “location where metal
dissolution takes place (i.e.
Fe→
→Fe2+ )”
n CATHODE: “location where O2, H+
or metal reduction takes place
(i.e. Fe3+→ Fe2+)”
n No specific location for anode
and cathode
n Anode and cathode move with
time
n Can be monitored, measured and
predicted
11
GENERALIZED CORROSION AT LOW TEMPERATURE
12
Can be uniform or not
CONTROL:
n Select proper metallurgy
n Corrosion allowance (function of
corrosion rate and required lifetime)
n Inhibitor
n Cathodic Protection
n Monitoring
Some metal-environment combinations
known to results in general corrosion:
Corrosion rate of various alloys in
CS - dilute mineral acid
CS - CO2 and/or H2S in aqueous phase boiling mixtures of 50% acetic acid
and varying proportions of formic acid.
CS - seawater
Test time 1+3+3 days. (by SANDVIK)
SS - organic acid at high T (i.e. 100- 200 °C)
Ti - concentrated sulfuric acid
GENERALIZED CORROSION AT LOW TEMPERATURE- CO2
13
An example of generalized corrosion at low temperature is CO2
corrosion on carbon steel.
Requires a presence of aqueous phase and it’s due to the low pH.
It can be tentatively predicted using a software
It’s a function of:
n PCO2
n Temperature
n System Fluid dynamics
(influences scale stability )
n Presence of H2S and/or organic acid
n O2 content
CONTROL: it can be controlled with CS + CA up to corrosion rate (CR)
0.6mm/y. For higher CR upgrade metallurgy to 304 (316 not necessary)
GENERALIZED CORROSION AT LOW TEMPERATURE - H2S
Another example of generalized
corrosion at low temperature on
carbon steel is Wet Hydrogen
Sulphide
corrosion.
(Note:
includes also risk of SSC and
hydrogen damage).
It requires a presence of aqueous
phase and it’s due to the low pH
and to the reaction between S and
Fe (formation of FeS scale)
The stability of FeS scale is
influenced by pH and presence of
contaminants (i.e. CN-)
The temperature rise increase CR
CR is hardly predictable
NOTE: CR is influenced also by pH, fine
metal
composition,
presence
of
contaminants (i.e. CN), etc... (by NACE)
14
GENERALIZED CORROSION AT LOW TEMPERATURE - H2S
H (atomic) can diffuse into the
metal causing:
n cracking
n blistering
n embrittlement
(see also SSC and
Hydrogen damage)
15
Graph
by
UOP
CONTROL: Wet H2S general corrosion can be controlled with CS + CA
up to corrosion rate (CR) 0.6mm/y. For higher CR upgrade metallurgy
to SS
The phenomenology related to hydrogen attack are taken into account
requiring HIC resistant specs (composition + test NACE TM 0284).
Note: consider as valid alternative SS cladding instead of CS HIC
resistant
GENERALIZED CORROSION AT LOW TEMPERATURE
16
GALVANIC CORROSION
n Preferential corrosion of one
metal of two or more
electrically connected
dissimilar
n It requires an aqueous
environment which is
corrosive to at least one metal
and with a non negligible
conductivity
n It’s related to the ∆V between
the metals in the considered
environment (i.e. see galvanic
series in seawater).
17
GALVANIC CORROSION
ALL the following parameter have to be verified to evaluate risk of
galvanic corrosion
n Verify the allowable ∆V:
è if it is not significant (i.e. the coupled metals are close in the
galvanic series measured in the considered environment) don’t
worry about CG
n Verify the medium corrosivity:
è if the fluid is not aggressive towards at least one of two coupled
metals (i.e CS - SS in neutral deoxygenated water) CG is not a
problem
n Verify the fluid conductivity:
è if it is very low (i.e. demi water of hydrocarbons) CG are not an
issue
n Verify cathodic/anodic areas:
è if the cathodic area is << of anodic area (don’t forget to consider
lining!!) galvanic corrosion can be tolerated (i.e. SS bolting on
CS flange)
18
GALVANIC CORROSION
19
CONTROL:
n Ratio cathodic/anodic areas (if the ratio increase the CR↑
↑).
n Control environment (i.e. pH↑
↑, remove O2... )
n Use of coating (either on both surfaces or on cathodic surface,
NEVER only on anodic surface)
n Use insulation kit to break electrical continuity
n Cathodic Protection
Metal coupling that can generate GC
(the first is attached):
CS-SS
CS-Copper alloy
CS-Ti
CS-Hastelloy SS-Ti
SS - Hastelloy
Insulation kit
GALVANIC CORROSION
20
GALVANIC CORROSION
21
GALVANIC CORROSION
22
PITTING CORROSION
n PITTING: form of extremely
localized attack that results in hole
in the metal. One of the most
dangerous and insidious form of
corrosion.
n It causes equipment to fail because
of perforation with only a small
weight loss
n Normally occurs in active/passive
metals (i.e. SS series 300) in
passive state
n Requires depassivating species
(i.e. chloride or other halides )
n Worse problem at low velocity and
high T
n Hard to detect and/or predict
UPSET
23
PITTING CORROSION
CONTROL:
n avoid metal/environment
combination susceptible to
pitting
n check environmental
conditions especially
è [Cl-] o [X-]
è Temperature
è O2
è Minimum fluid velocity
A parameter to evaluate pitting
resistance of SS is PREN (pitting
resistance equivalents number):
PREN = Cr + 3.3 Mo + 16N
Critical pitting temperatures (CPT) for SAF 2205,
AISI 304 and AISI 316 at varying concentrations of
sodium chloride (potentiostatic determination at
+300 mV SCE), pH»6.0 (by SANDVIK)
UPSET
24
PITTING CORROSION
25
Examples of metals susceptible
to pitting in chlorides
environment:
n SS (Ferritic, Austenitic,
Duplex)
n Fe-Ni-Cr Alloy (Incoloy)
n Aluminum Alloy
UPSET
n Copper Alloy
Immune
Ti
Alloy C
Alloy 625
Very resistant
90/10 Cu/Ni
Admiralty brass
Resistant
70/30 Cu/Ni
Tin
Al bronze
Acceptable
Monel
316 (+ CP)
Alloy 825
Alloy 20
Pitting resistance in seawater
Not Acceptable
SS series 400
304
Nickel
PITTING CORROSION
26
PITTING CORROSION
27
CREVICE CORROSION
Selective corrosion in crevice
n CC requires a stagnant zone
where it’s possible to develop
different conditions from bulk
(inhibitor, oxygen, pH, Cl-)
n CC requires an aggressive
environment (i.e. presence of
chloride)
n If temperature
likelihood ↑
↑
crevice
UPSET
28
CREVICE CORROSION
CONTROL:
n Use materials less sensitive to pitting (the corrosion mechanisms
are similar therefore a material resistant to pitting corrosion is also
resistant to crevice corrosion. See slide 99)
n avoid stagnant zone
n don’t use threaded connections
n control O2 content
Some materials susceptible to CC:
è SS
è Ni alloy
UPSET
è Ti
Preferentially locations for CC:
n Flanged connection
n Tube/Tubesheet connection
n Threaded connections
n Plate Heat Exchangers
29
CREVICE CORROSION
30
CREVICE CORROSION
31
UNDER DEPOSIT CORROSION
Corrosion enhanced by the
presence of scales (can be
aggressive i.e NH4Cl or not)
Under deposit corrosion results
from difference between local and
bulk environment (i.e oxygen, pH,
presence of aggressive ions Cl. See
also crevice and pitting corrosion)
If chloride are present H+ “drawn”
under deposits (pH drops below 4
increasing corrosion rates)
Most common materials are
subjected to UDC including CS,
austenitic SS, nickel alloy (Inconel
625, Hastelloy and Ti are very
resistant)
32
UNDER DEPOSIT CORROSION
Refinery examples:
any location in which scaling and/or
fouling occur especially if chloride or
oxygen are present
CONTROL TECHNIQUES
n treat the source of the problem (i.e.
corrosion or fouling)
n design equipment to minimize
deposition. Metallurgy may solve
corrosion problem but not performance
loss
n antifoulant may be helpful
33
UNDER DEPOSIT CORROSION
AMMONIUM BISULFIDE
n frost from gas to solid at a temperature depending on NH3 H2S
concentration
n Is corrosive vs CS but not vs SS or higher alloy
n Causes very rapid fouling
Refinery examples
n REACs (hydrotreaters/hydrocrackers)
n Crude unit overhead
n FCC (overhead in separator section)
CONTROL
n wash water
è use continuous washing (20%min water not vaporized)
è inject upstream of ammonium bisulfide dew point
n Use balanced piping for REACs
n Upgrade metallurgy
34
UNDER DEPOSIT CORROSION
AMMONIUM CHLORIDE
n frost from gas to solid at a temperature depending on NH3 HCl
concentration
n Is corrosive vs CS and SS. Ti and Inconel 625 may offer sufficient
protection
n Causes very rapid fouling
REFINERY EXAMPLES
n Crude unit overhead
n hydrotreaters (REACs, overhead in separator section)
n Catalytic reformer (REAC, separator, stabilizer, recycle gas
compressor)
n FCC (overhead in separator section)
CONTROL
n wash water
è use continuous washing (20%min water not vaporized)
è inject upstream of ammonium chloride dew point
n Use balanced piping for REACs
n Upgrade metallurgy (expensive solution)
35
STRESS CORROSION CRACKING
Cracking corrosive process that requires the simultaneous
presence of:
n Material in passive state susceptible to attack
nAggressive environment
nstress state
èresidual (i.e. welds)
èapplied (i.e. bends)
UPSET
36
STRESS CORROSION CRACKING
Table from ASM Vol 13 Corrosion
37
STRESS CORROSION CRACKING
Main type of SCC
n Chloride stress corrosion cracking (CSCC)
n Sulphide stress cracking (SSC)
n Alkaline stress corrosion cracking (ASCC)
n Polythionic Acid Stress Corrosion Cracking (PASSC)
n Cracking in H2O-CO-CO2 system
UPSET
38
CHLORIDE STRESS CORROSION CRACKING
39
Material susceptible to CSCC
n austenitic SS, duplex , ferritic
(sensibilized)
n Fe-Cr-Ni alloy (Incoloy)
n Copper alloy
n Bronze/Brasses
n Aluminum
n Cobalt alloy (i.e. Stellite)
UPSET
View of chloride stress corrosion cracking in a 316
stainless steel chemical processing piping system.
Chloride stress corrosion cracking in austenitic
stainless steel is characterized by the multibranched "lightning bolt" transgranular crack
pattern. (Mag: 300X)
CHLORIDE STRESS CORROSION CRACKING
40
For SCC Ni content is
fundamental
SS serie 300
CONTROL:
n limit O2 content
n limit stress (∃
∃ threshold value)
n Control temperature
n Control pH
N.B. H2S lowers CSCC limits
UPSET
SCC resistance in oxygen-bearing (abt. 8 ppm)
neutral chloride solutions. Testing time 1000
hours. Applied stress equal to proof strength at
testing temperature. (by SANDVIK)
SULPHIDE STRESS CRACKING
41
SSC is defined as cracking of a metal under
the combined action of tensile stress and
corrosion in the presence of water and H2S
SSC is a form of hydrogen stress cracking
resulting from absorption of atomic hydrogen
that is produced by the sulfide corrosion
reaction on the metal surface
SSC is influenced by:
n Chemical composition (P,S,Mn), hardness,
metal thermal treatment
nTotal tensile stress (applied plus residual)
n Hydrogen flux (function of [H2S], pH, CN-,
etc..)
n Time (Note: short term conditions i.e.
shutdowns can be sufficient)
n Temperature (increase H 2S dissociation
and H diffusion)
H2S SSC Cracks in a 17-4 pH
stainless steel
UPSET
SULPHIDE STRESS CRACKING
42
Some environmental conditions known to cause SSC are those
containing free water (in liquid phase) and:
n >50 ppmw dissolved H2S in the free water or
n free water pH<4 and some dissolved H2S present or
n free water pH>7,6 and 20ppmw dissolved HCN in the water and
some dissolved H 2S present
n >0.0003 MPa absolute partial pressure H2S in the gas in processes
with a gas phase
CONTROL:
For Refinery apply NACE MR0103
For upstream (oil and gas production) apply NACE MR0175
Note: Pay attention to thermodynamic model used in the simulators
and to hypothesis to calculate % H2S in free water
UPSET
ALKALINE CRACKING
cracking in caustic environment
carbonate cracking
cracking in amine environment
Main materials involved:
n Carbon steel
n Low alloy steel
n Stainless steel
n Copper alloy
UPSET
43
CAUSTIC CRACKING
Cracking due to
exposition of CS to hot
caustic solution (i.e.
NaOH, KOH)
CONTROL: use the
materials indicated on
Caustic Soda Service
Graph (see also SR) by
NACE
Note: If for the service
austenitic SS has been
specified, check
chloride concentration
and T max.
UPSET
Caustic Soda Service Graph by NACE
44
STRESS CORROSION CRACKING
45
STRESS CORROSION CRACKING
46
STRESS CORROSION CRACKING
47
STRESS CORROSION CRACKING
48
STRESS CORROSION CRACKING
49
AMINE CRACKING
50
Cracking caused by amine (mainly due to dissolved CO2 e H2S).
Amine cracking happens preferentially in the heat affected zone (HAZ).
Lean amine is not corrosive vs CS and it shows less probability to
cause cracking.
MEA is more aggressive than DEA o MDEA
If temperature ↑ cracking likelihood ↑ (consider also short term
condition, i.e. Steam out)
CONTROL:
è SR (included PWHT) in accordance with API 945 (595 °C < T <
649°C, min holding time 1h)
è hardness < 200HRB
SR is suggested, function of used amine, at the following operating T:
nMEA : all operating T
nDEA: T > 60°C
nMDEA : T> 82°C
UPSET
CRACKING IN CO-CO2-H2O SYSTEMS
51
It can happen in pressure system with the simultaneous presence of
CO-CO2-H2O
n low T (maximum risk in the range 20-60°C)
n minimum CO and CO2 pressure required
CONTROL:
Check environmental conditions (T, water, PCO & PCO2)
Use SS (12 Cr o 304; 316 not necessary)
Range of SCC susceptibility
CO partial pressure (kPa)
1400
1200
1000
800
600
400
200
0
0
200
400
600
800
1000
1200
CO2 partial pressure (kPa)
Published data
SASOL
Mossgas
1400
1600
1800
SENSITIZATION ISSUES (INTERGRANULAR CORROSION)
Main degradation forms related:
n Sensitization
n Weld decay
n Knife line attack
n Polythionic acid stress corrosion
cracking
MECHANISM:
1) A high temperature exposure
allows the reaction between
Cr and C.
2) Cr carbides precipitates at grain
boundaries.
3) Cr depletion in areas surrounding
to grain boundaries. (when Cr
below 12% the steel is no more SS
and corrode like CS).
52
SENSITIZATION AND WELD DECAY
Sensitization
n is not a corrosion mechanism but the Cr depletion may generate
intergranular attack.
n May occur rapidly due to: weld, heat treatment and operating
temperature.
n The sensitization range (temperature and time) is related to the
material.
Weld decay
n The Cr depletion is related to the
heating in areas surrounding the weld.
n Varies with welding conditions
n varies with distance form the weld
Knife line attack
n Same mechanism of weld decay
n on chemically stabilized material
Heat affected zone (HAZ)
53
SENSITIZATION CONTROL TECHNIQUES
Sensitization control
n Materials selection:
è normal and high carbon grades: Carbon content 0,03 % - 0,10
l Ferrous (i.e. 304/316) and Ni-Cr alloys
Subjected to sensitization.
è low carbon grades: below 0,03 %
l i.e. 304L, 316 L, Hastelloy C-276
Do not sensitize under welding conditions but are
subjected to sensitization under operating conditions
è Chemically stabilized material (Nb or Ti)
l I.e. 321, 347, Incoloy 801, 825, alloy G, Inconel 625
Ni and Ti form carbides avoiding Cr depletion.
Thermal treatment (stabilization) avoids
sensitization over long term exposure.
l Stabilization heat treatment should be recommended
n Procedure mistakes
è Cleaning with oily rag before welding introduces C
è PWHT in the sensitizing time-temperature range
54
INTERGRANULAR CORROSION
55
POLYTHIONIC ACID STRESS CORROSION CRACKING (PASCC)
56
Intergranular corrosion and cracking
caused by the simultaneous presence
of:
n Sulfide scale
n Sensitized material
n Oxygen
n Stress (residual or applied)
n Water
n Polythionic Acids (H2SxOy) form
(usually during shut down) for reaction
of sulfide scale with H2O e O2
Main material subjected to sensitization:
n Austenitic or Ni alloy (also low carbon
or stabilized) operating at high T (i.e. 370
°C < T < 815°C for 304/316)
n Austenitic or Ni alloy (not stabilized)
welded
Polythionic acid stress corrosion cracking of
type 310 stainless steel. The item was
exposed to sulfur containing natural gas in a
continuous flare
UPSET
POLYTHIONIC ACID STRESS CORROSION CRACKING (PASCC)
Refinery examples:
n hydrodesulfurizers
n hydrocrackers
n hydrogen reformers
n FCC
n Fired heaters (both external and internal)
UPSET
CONTROL: follow guideline NACE RP0170
n Exclusion of oxygen (air) and water by using a dry nitrogen purge
n Alkaline washing with soda ash. Avoid washing of zone that can’t
be drained
n Exclusion of water by using a dry purge with a dew point lower
than -15°C
57
CORROSION UNDER INSULATION
For further information on CUI see NACE RP 0198
58
HYDROGEN DAMAGE
Atomic hydrogen even produced by low temperature corrosion
phenomena may diffuse through metal surface causing hydrogen
damage.
Hydrogen damage is recognized under various forms:
n Blistering
n Hydrogen Induced Cracking (HIC)
n Stress Oriented Hydrogen Induced Cracking (SOHIC)
n Hydrogen Embrittlement
n High Temperature Hydrogen Attack
UPSET
59
BLISTERING-HIC-SOHIC
Main steps of blistering and HIC
n Atomic hydrogen diffuses inside the
metal bulk
n Inside the metal atomic hydrogen
meets the voids (rolling defects) and
inclusions (MnS) and re-combines in
molecular hydrogen (H2)
n Gradually, molecular hydrogen
collected in voids and inclusions
increases the pressure reaching up
to 10 GPa.
n The elevated pressure evidenced by
surface blistering may lead to local
(stepwise) and complete rupture of
the plate.
n SOHIC is related to residual stresses
presents in the metal.
UPSET
60
BLISTERING-HIC-SOHIC
Influencing and control parameters:
61
UPSET
n Chemical composition of the process fluids (presence H2O,
pH, H2S, CN, As, Sb)
n Voids and inclusions presence
n Metal chemical composition and thermal treatments.
n Residual stresses (only for SOHIC)
n Construction and welding and test procedure according
standards. (NACE MR 0175, NACE 0103, NACE TM0284, API
945)
BLISTERING-HIC-SOHIC
62
HYDROGEN EMBRITTLEMENT
Embrittlement caused by the
hydrogen diffusion through the
metals.
Possible Hydrogen sources:
n General corrosion
n Galvanic corrosion
n Overprotection of cathodic
protection.
Influencing factors:
n Enhanced by CN, As, Sb
presence.
n May occur on CS, alloyed steels,
nickel alloys, Titanium (T > 71° C)
Copper alloys are considered
immune
UPSET
63
HYDROGEN DAMAGE
64
Critical areas:
è “Rich” section of amine units.
è Sour water stripper.
UPSET
è Hydrodesolfurization units.
è FCC units.
Hydrogen damage control:
n Appropriate material selection
è Reduction the allowable metal inclusions (S, Mn and P content).
è Ca and rare earth addition (shape control of residual inclusions).
è Steel HIC resistance according NACE TM0284.
n Optimization of process conditions (i.e. H2O, pH)
n Construction and welding according standard (i.e. NACE MR0175
NACE 0103).
n Correct cathodic protection design and operation.
n Use of insulation kit for different metals in electrical contact.
EROSION-CORROSION
♦ Degradation mechanism
accelerated by flow conditions of a
corrosive fluid in contact with metal
surface
♦ Mechanism:
Corrosive fluid reacting with metal
creates a film scale
Fluid removes mechanically the
scale exposing uncorroded metal
Material
CS
Ad. Brass
70-30 Cu Ni (0.05% Fe)
70-30 Cu Ni (0.5% Fe)
Typical corrosion rates in seawater mdd
1ft/sec
4 ft/sec
27 ft/sec
34
72
254
2
20
170
2
199
<1
<1
39
65
EROSION-CORROSION
Factors influencing erosioncorrosion:
n Velocity and fluid turbulence
n Temperature
n Multiphase flow
n Suspended solid
n Galvanic effect (i.e.: CS-SS and
CS-CuNi in seawater)
CONTROL:
n Material Selection or lining (i.e. Cu-Ni 66-30-2-2 instead of CuNi 70/30).
n Check allowable velocity
n Localized preventive measures (i.e. ferrule on tubes inlet).
n Change environment (i.e. inhibitor, filtering, temperature).
66
EROSION-CORROSION
67
68
MICROBIOLOGICAL INDUCED CORROSION (MIC)
MIC refers to corrosion
influenced by the presence
and activities of
microorganisms and/or their
metabolites
Microorganism (i.e. fungi,
bacteria or algae) can be
aerobic or anaerobic
Generally MIC shows jeopardized attack on CS, localized on SS (i.e.
pitting)
Microorganism’s growth is influenced by pH, temperature and “food”
availability (peak between 30 e 40 °C)
Stagnant zone increase attack severity
69
MICROBIOLOGICAL INDUCED CORROSION (MIC)
Refinery examples:
n Cooling water systems
n Water layer in tanks
n Following hydrotesting
CONTROL:
n Use Biocide addition
n High thick Coating (i.e. coal tar)
n Cathodic Protection (+950 mV)
n High quality hydrotest water
n Avoid wet dead legs
70
71
CORROSION AND DEGRADATION
MECHANISMS
High temperature corrosion mechanisms
HIGH TEMPERATURE CORROSION MECHANISMS
n NAPHTENIC ACID CORROSION
n HIGH TEMPERATURE OXIDATION
n SULFIDATION
n HIGH TEMPERATURE HYDROGEN DAMAGE
73
NAPHTENIC ACID CORROSION
Generalized corrosion at high T (230400 °C) caused by naphtenic acids for
crude with TAN > 0.5 (ASTM D 974
T.A.N. as mg KOH/g) or TAN > 0.35 for
some licensor.
∃ several type of naphtenic acids
Naphtenic acids are very aggressive especially close to their boiling
points (thus can attack selectively some locations of the unit )
n Metallurgy: CS and Cr alloy (i.e. 5 - 9 - 12Cr o 304/316 std) are
readily attacked
n Sulfur content: especially at low fluid velocity, sulfur can mitigate
corrosive attack
n Velocity: high velocity (>2.7 m/s) increases corrosion rate
74
NAPHTENIC ACID CORROSION
Refinery examples:
n Heaters and Transfer Line in CDU
n Diesel section of CDU column (pump-around)
n Atmospheric column residue
n Vacuum column residue
n Gas oil section of VDU
CONTROL:
n N.B. Check TAN for each cut with operating temperature in the
range 260 - 400°C
n Stainless steel 317 o 316 with Mo 2.5%min
n Monitoring + inhibitor (only for short run)
n Use blending to reduce TAN
n Neutralization with NaOH (pay attention on caustic embrittlement)
75
HIGH TEMPERATURE OXIDATION
Generalized corrosion caused by
direct oxidation of base material
(liquid water not required)
Oxidation issues
n O2 Concentration
n Alloy composition
n Metal temperature
The source of O2 can be also
steam or CO2
The scale composition
influences CR
Microstructure of iron oxides formed on iron by
high-temperature oxidation in air
76
HIGH TEMPERATURE OXIDATION
Refinery examples:
n Heaters
n Boilers
CONTROL:
n Improve metallurgy
(with alloy containing
Cr, Ni, Si, Al)
Control environmental conditions, especially:
n Sulfur (Increase corrosion rate)
n metals (i.e. V which causes V2O5 formation) in fuel
n Temperature (if scale ↑ thermal exchange↓
↓ and lifetime↓
↓)
77
SULPHIDATION
Reaction between Sulfur and metal or alloy at high temperature.
Can cause generalized corrosion @ T>260 °C
CR is influenced mainly by T and %S (or H2S)
Refinery examples:
n Topping and Vacuum (@ T >260°C)
n HDS (hot heat exchangers, heaters and reactor)
n Sulphur Recovery Unit
%Cr is fundamental to resist to sulfidation attack. Generally low
chrome alloy are used with %Cr higher and higher (1.25-2.25-5-7-9
Cr) up to stainless steel (as 12Cr like 405 and 410) or austenitic
(304 or 316)
78
SULPHIDATION
CONTROL:
Use appropriate metallurgy considering CR calculated by available
curves (function of metal T, alloy composition and %S for Mc Conomy
or H2S for Couper Gorman)
n Mc Conomy (API) based on total sulfur content:
79
SULPHIDATION
80
CONTROL:
Use Couper Gorman for fluid containing high H2 and H2S concentration
(see also Nelson curves on API 941 for HTHA)
Available for several material (i.e. CS, low Cr alloy and SS)
Couper Gorman Curves for carbon steel and 18-8 stainless steel
HIGH TEMPERATURE HYDROGEN ATTACK (HTHA)
81
High temperature hydrogen can attack
steels in two ways :
n Surface decarburization (slight,
localized reduction in strength and
hardness and an increase in ductility)
n Internal decarburization and fissuring
(CH4 formation and high localized
stresses which lead to the formation of
fissures, cracks or blister in the steel)
Factors influencing HTHA:
n Temperature
n H2 pressure
n Stress (i.e. welds)
n Time (∃
∃ incubation period)
Hydrogen attack corrosion and cracking
on the ID of an 1800 psig carbon steel
boiler tube.
HIGH TEMPERATURE HYDROGEN ATTACK (HTHA)
82
CONTROL:
Use Cr-Mo alloy instead of CS (reduces
the amount of available carbide)
SS are practically immune from HTHA
For CS and Cr-Mo alloy refer to API 941
Note:
èC-0.5Mo, usually, is not allowed in
H2 service
èCladding should not be considered
as material resistant to HTHA
(therefore also base material have
to be resistant)
Solids deposition and hydrogen attack
corrosion at the ID weld in an 1800 psig
carbon steel boiler tube. The arrow
marks the direction of flow. (~1X)
HIGH TEMPERATURE HYDROGEN ATTACK (HTHA)
83
Nelson curves (API 941)
N.B. Add safety margin, below the relevant curve,when selecting steels (11 °C min)
STATISTIC RELEVANCE OF CORROSION FAILURES
nCorrosion causes the 55%
of the failures in chemical
plants (the remaining 45% of
the failures are related to
mechanical reasons).
n General corrosion and SCC
show the higher occurrence
in corrosion failures (in sum
they account 51%).
Types of corrosion failures (duPont)
others corrosion
6%
General
27%
Stress Corr.
Cracking
24%
High temperature
corrosion
2%
Erosion-corrosion
7%
Crevice
2%
n Crevice corrosion causes
only 2% of the failures while Weld corrosion
5%
pitting the 14%.
nThe sum of Intergranular
and
weld
corrosion
is
relevant (15%).
Pitting
14%
Corrosion fatigue
3%
Intergranular
10%
84
“Il campo della corrosione è con molta aderenza
paragonabile a quello della medicina. Per I materiali, la
corrosione è indubbiamente la più insidiosa delle cause di
decadimento e di morte e al corrosionista si presenta il
compito in genere assai arduo, di diagnosticare il male, di
stabilirne le cause, di prevenirlo ove possibile altrimenti di
reprimerlo o contenerlo in limiti accettabili… [A questo
scopo il corrosionista deve]… pazientemente costruirsi il
suo atlante di anatomia patologica dei materiali esposti ai
più svariati ambianti aggressivi, edificare il corpus della sua
diagnostica, sviluppare una sempre più efficace
farmacologia anticorrosionistica.”
Roberto Piontelli, 1961
MATERIAL SELECTION AND
CORROSION CONTROL
Selection criteria, material properties
and cathodic protection
MATERIALS AND CORROSION PROTECTION
n
n
n
n
n
n
n
n
n
CONDITION ASSESMENT AND MATERIAL SELECTION
CARBON STEEL
LOW ALLOYED STEELS
STAINLESS STEELS
COPPER ALLOYS
NICKEL ALLOYS
TITANIUM ALLOYS
POLIMERIC MAERIALS
CATHODIC PROTECTION
87
MATERIAL SELECTION
Phase sequence
Scope of corrosion activities
1. Process
development
Conditions assessment
2. Material selection
Ensure the required service life time
Costs decrease
3. Process and
material optimization Improve the reliability of the unit
4. Engineering,
Procurement,
Construction
Ver. corrosion protection measures i.e. CP
Control galvanic corrosion
Control erosion corrosion
On Stream Inspection
88
1. CONDITIONS ASSESSMENT
Environment type
(water/oil content)
TDS &
TSS
Contaminants
and corrodents
Cl , H2S, CN-, NH 3 …
Temperature
(local)
Oxidizers
O2, Cl2, Fe3+, Cu2+…
Fire hazard
Marine environment
Pressure
Chemical
composition
Physical
External conditions
Underground
Fluid dynamic
Conditions
Thermal insulation
Chemical
composition
89
Condensation
and dew point
(local)
Atmospheric env.
Upset conditions
Thermodynamic
Physical
Solid
Precipitation
Thermodynamic
Phase settling
Time extension
Probability
2. MATERIAL SELECTION
Conditions
90
Life Time
experience in similar units
Density
Heat treating
Strength
Experience
and literature
Material sel. in similar
service within the prj
Corrosion
allowance
Costs
Metallurgy
Corrosion
protection
Galvanic couplings
Material
Joining techniques
Availability
Fabricability
Procurement
time
Pre-fabrication
Construction
dimensions
Spare parts
Fittings
3. PROCESS AND MATERIAL OPTIMIZATION
ØExam of the whole unit
Conditions
assessment
Material
selection
Process Engineer
Corrosion Engineer
Process
development
ØScope
Decrease the project costs
Avoid over and under specification
Improve the reliability of the unit
91
CARBON STEEL
n The material
Chemical composition based on Fe and C, can be adjusted to
improve the resistance to specific degradation mechanism (i.e. HIC)
n Typical conditions:
By far the most common material used up to 400°C
in refineries due primarily to a combination of
strength, availability, low cost, and resistance to fire.
n Main contaminants and corrodents:
Halides (chlorides), sulfides, ammines, dry ammonia, carbonates,
CO2+H2O+CO, cyanides, Hydroxides, nitrates, CO2+H2O, acids,
oxygenated demi water.
n The degradation mechanisms to be verified:
General corrosion, stress corrosion cracking, crevice, under
deposit, under insulation, galvanic attack, hydrogen damage,
erosion corrosion, high temperature damage (almost all).
92
CARBON STEEL
Specific corrosion protection measures.
n Design according to soda chart, Mc Conomy, Couper Gorman,
Nelson where applicable.
n Selection of inhibitors (i.e. acidic water, cooling water, boiling
water).
n Cathodic protection to control general, galvanic, MIC and crevice
corrosion.
n Anodic protection to control general corrosion.
n Polymeric lining (epoxy, PTFE, GRP, rubber)
to control corrosion at low temperature.
n PWHT to control SCC.
n Electrical insulation from others metals to control
galvanic corrosion.
n Water injection to control under deposit corrosion.
93
LOW ALLOYED STEEL
The materials:
n Typical conditions:
For high temperature
service, or hydrogen and
sulfidant atmosphere.
Chemical Composition
94
Max Temperature °C
0,5% Mo
500
1% Cr 0,5% Mo
600
1,25% Cr 0,5% Mo
600
2,25% Cr
1% Mo
625
5% Cr 0,5% Mo
650
9% Cr
650
1% Mo
n Present the same contaminants and corrodents of Carbon steel.
n The degradation mechanisms to be verified:
As per CS. Specifically Hydrogen high temperature damage and
high temperature sulfidation.
n Corrosion prevention measures:
Design according Nelson diagram, Couper Gorman and Mc
Conomy to realize correct selection and evaluation of corrosion
allowance.
STAINLESS STEEL
95
n The materials:
Designation
Type
Metallurgy
12-13 Cr
405, 410, 410 S
Martensitic, Ferritic
18 Cr 8 Ni
304, 304L, 321, 347
Austenitic
18 Cr 10 Ni Mo
316, 316 Ti
Austenitic
22 Cr 5 Ni Mo N
S31803 (2205)
Duplex
25 Cr 7 Ni Mo N
S32750 (2507)
Super Duplex
20 Cr 18 Ni 6 Mo Cu N
S31254 (254 SMo)
Super Austenitic
20 Cr 24 Ni 6,5 Mo
(Al-6X)
Nickel alloy
n Typical conditions:
Acidic and saline water, high temperature
and low temperature, waste water,
demi water, organic acids.
n Main contaminants and corrodents:
Halides (chlorides), hydroxides (wet and dry), sulfurous acid (on
austenitic), organic acids, Hydrogen sulfide and (by external
side) Vanadium, molten zinc and molten aluminum.
STAINLESS STEEL
n The degradation mechanisms to be verified:
General corrosion, Pitting, SCC, crevice, galvanic, MIC, erosion
corrosion, weld decay, liquid metal embrittlement.
n Corrosion protection measures:
è Design taking into account the resistance of the different alloys
in considered environment.
è Selection of inhibitors.
è Thermal treatments to control SCC and intergranular corrosion
cracking.
è Chemical cleaning (against PASCC) and passivation.
è Electrical insulation from others metals to control galvanic
corrosion.
96
FERRITIC AND MARTENSITIC STAINLESS STEELS
n 11-13% Chrome (type 405 and 410 S)
Primarily used for clad lining
n 11-13% Chrome (type 410)
ferritic or martensitic stainless steel extensively applied for
standard trim on process valves, pump impellers, vessel trays, tray
components and exchanger tubes.
Corrosion resistance
è excellent resistance to sulfur at high temperature.
è good resistance to hydrogen sulfide at low concentrations and
intermediate temperatures.
97
AUSTENITIC STAINLESS STEEL
Variables influencing the behavior of austenitic stainless steels
in salted water:
n Temperature:
50° C is accepted as the minimum temperature for the
occurrence of stress corrosion cracking and pitting in slightly
salted water (100-200 ppm).
n Chloride content:
In stress relieved structures, the maximum allowed chloride
content to avoid pitting and crevice (below 50°C) is related to
the alloy
Type
304
316
Cl100 ppm
300 ppm
(these limits can be lower for some Licensor i.e. 50 ppm for UOP)
98
AUSTENITIC STAINLESS STEEL
n Metallurgy
selection is realized considering critical temperature which is
the minimum temperature at which pitting or crevice may
occur in ferric chloride solution.
CSCC occurrence have to be considered separately.
99
COPPER ALLOYS
n The materials
Alloy type
Main composition
Aluminium bronze
92% Cu, 8% Al
Aluminium brass
77% Cu, 21% Zn, 2% Al, 0.04% As
Admiralty
71% Cu, 28% Zn, 1% Sn, 0.04% As
90-10 Cu-Ni
10% Ni, 1% Fe, Cu rem.
70-30 Cu-Ni
30% Ni, 1% Fe, Cu rem.
66-30-2-2 Cu-Ni
30% Ni, 2% Fe, 2 %Mn, Cu rem.
n The typical applications
Seawater exchangers, water pipes,
brackish water equipment.
100
COPPER ALLOYS
nMain degradation
mechanisms
Erosion corrosion and
impingement attack, stress
corrosion cracking (in
presence of 1 ppm of
ammonia), selective leaching
(Immune to hydrogen
damage, and prevent
biofouling)
nCorrosion protection
measures
correct design according
standards (BS MA18 in the
graph).
Check ammonia presence
(UPSET conditions)
Erosion ferrules (in Teflon or
special Cu Ni alloys Cr
modified)
Maximum seawater velocities for continuos flow conditions
m/sec (ref.:BS MA 18)
101
TITANIUM ALLOYS
The materials
n Titanium is a reactive metal and as the other materials of the
group forms spontaneously a superficial oxide film which
ensure protection from the environment.
n The corrosion resistance is related to the stability and the
continuity of the oxide layer (on-off corrosion behavior).
n The reactive metal group is formed by (increasing by
corrosion resistance): Titanium, Zirconium, Niobium and
Tantalum. The corrosion behavior of these materials shows a
large amount of similarities.
ASTM grade
Composition
Gr 1,2,3,4 unalloyed (O and N content)
Gr 7, 11
0.2 Pd
Gr 12
0.8 Ni 0.3 Mo
Gr 16, 17
0.04 Pd
102
TITANIUM ALLOYS
n In which conditions:
Seawater and desalinization plant, organic acid, in oxidizing and
mildly reducing wet environments.
103
TITANIUM ALLOYS
n Main contaminants and corrodents:
Wet Fluorides (and halides in high concentration), methanol plus halides,
nitric acid fuming, nitrogen tetroxide, gaseous water free halides,
chlorinated solvents, concentrated reducing acids.
n Degradation mechanism to be verified
General corrosion, pitting, crevice, SCC, catastrophic oxidation, galvanic*,
hydrogen embrittlement.
104
TITANIUM ALLOYS
n Welding of titanium
1)
The weld of Chemically Pure and Pd alloys (ASTM gr. 1, 2, 3,
4, 7, 11, 16, and 17) shows the same corrosion resistance
as the bulk material.
2)
Like all reactive metals at high temperature reacts strongly
with atmospheric oxygen.
3)
Can be welded with GTAW or GMAW (same equipment used
for SS 316 or nickel alloys).
4)
Argon or helium have to be be used to protect the weld
in welding chamber (shop) or welding shoes (construction
site).
5)
The weld quality verified easily for acceptance
• Visual examination of “as weld” surface
• hardness measurement is highly sensitive to oxygen pickup
105
NICKEL ALLOYS
n Materials
Alloy type
Incoloy 800
Incoloy 825
Inconel 625
Inconel 600
Inconel 601
Hastelloy C-276
Monel 400
Main composition
33% Ni, 21% Cr, 40%Fe, 0.1% C, 1% Al+Ti
43% Ni, 22% Cr, 3% Mo, 2% Cu, 0.04% C, Fe Bal
43% Ni, 22% Cr, 9% Mo, 3.5% Nb, 0.04% C
76% Ni, 16% Cr, 8% Fe, 0,2 Cu, 0.08 C
60% Ni, 23% Cr, 16% Fe, 1% Al Cu, 0.1 C
57% Ni, 15% Cr, 16% Mo, 1% Fe, 0.02% C
66% Ni, 31% Cu, 1.4% Fe, 0.15% C
n Advantages:
è Very resistant (as a function of specified type) to many
environments
è In aggressive reducing environments are mandatory selection
n Disadvantages:
è High cost (GdP will be not so happy!!! )
è Possible availability problems for some alloy
106
NICKEL ALLOYS
107
TYPICAL ENVIRONMENTS
n Hastelloy C/C276, Inconel 625
è High resistance to acid (both oxidizing and reducing)
è excellent resistance in chloride and/or H2S environment
è High resistance vs underdeposit corrosion
n Inconel 601, Incoloy 800
è High temperature resistance
n Incoloy 825
è High resistance in chloride and/or H2S environment (lower than
Hastelloy C-Inconel 625)
è High resistance vs underdeposit corrosion (but can fail with NH 4Cl)
n Monel
è High resistance to hot alkalis
è High resistance to acid (especially HF)
POLYMERIC MATERIALS
n High molecular weight organic materials that can be formed into
useful shapes.
n Can be used for piping and equipment (thermosetters and
thermoplastics) or for gaskets (elastomers)
Polymeric materials
In refinery
Thermoplastics
PE
PTFE
PVC
Thermosetters
Glass fiber epoxy resin
Glass fiber vynil ester ep. resin
Glass fiber Poly ester ep. resin
Elastomers
Viton (Flueelastomers)
Kalrez (perfluoelestomers)
NBR
108
THERMOPLASTICS
n Are characterized by the softening with
the increase of temperature and return
to their original hardness when cooled
(most are weldable).
n Degradation mechanisms are different
from metals:
Swelling, softening, loss of mechanical
properties, hardening and discoloration
(no electrochemical mechanisms
involved). Degradation may be caused
by heat, solar exposure and UV.
n For correct material selection and
design are necessary: life time,
temperature (!), environment and
pressure.
n Main couple material-environment are:
PE(or PP)-water, PVC-mineral acids,
PVDF-acids (at higher pressure and
temperature).
109
Main Materials:
Polyethylene (PE)
Polypropylene (PP)
Polyvinyl chloride (PVC-CPVC)
Polyvinylidene Fluoride (PVDF)
Teflon (PTFE)
THERMOPLASTICS
n Advantages
è Excellent chemical resistance to
water environment,
l PTFE can withstand practically all
refinery environments below 200°C
è Easy welding and installation (not
for all)
è No protection required in
underground service
n Disadvantages
è Rapid decrease of properties with
the temperature increase.
è Chemical resistance to
hydrocarbons
è Not suitable in fire hazard area
110
THERMOSETTERS
n Are characterized by the thermal
degradation when exposed to
heating.
n Thermosetters are generally used
as matrix for composite material.
Glass is generally used as fiber.
n Same degradation mechanism of
thermoplastic:
Swelling, softening, loss of
mechanical properties, hardening
and discoloration. Higher
resistance than thermoplastics.
111
Main matrix Materials:
Epoxy resin
Vinyl ester epoxy resin
Phenolic resin
THERMOSETTERS
Main applications are:
Firewater, cooling water, high
pressure water lines (special types up
to 280 Bar), sewer.
Advantages
è Excellent chemical resistance to
aqueous environment
è No protection required in
underground service
Disadvantages
è Installation difficulties
è Design and installation know how
è Not suitable in fire hazard area
è Sensitivity to vibrations and
mechanical stresses
112
CATHODIC PROTECTION
n History
In 1824 Sir Humphrey Davy discovered that is possible to protect the
copper of royal ships from marine corrosion by electrically coupling it
with iron.
n Basic Principle
The metal dissolution is reduced trough the application of cathodic
current that may originates from:
è the corrosion of a less noble metal (sacrificial cathodic protection)
è the conductive anode and ∆ V (current impressed cathodic
protection)
n Scope of CP applications:
è Protect from wet and soil
corrosion coated steel.
è Allow the use of carbon
steel avoiding the material
upgrade.
è Minimize the cost of CS
coating maintenance.
113
CATHODIC PROTECTION
Cathodic protection techniques
n Sacrificial cathodic protection
è Use of anodic metal
l Magnesium (t< 40°C)
l Zinc (t < 40°C)
l Aluminum
(Cl- > 1000 ppm or t > 40°C)
è Anode connection with cathode
l direct (economical)
l trough a electrical resistance
(improve the control and avoid
under and over protection)
è Reference electrodes
l Allows monitoring and verification
of corrosion for cathodically protected surfaces
114
CATHODIC PROTECTION
Cathodic protection techniques
n Impressed current cathodic protection
è anode material
l Ti Mixed metal oxide coated
l High silicon iron
l Ceramic electrodes
è current generation
l an external DC current
source is necessary
è reference electrodes
l the use is mandatory in
conjunction with current
control system
115
CATHODIC PROTECTION
n Design parameters
è Temperature (important for anode selection)
è pH
è Chemical composition (Cl- and ions content)
è Conductivity (high conductivity = aggressive condition)
è Redox potential (i.e. oxygen content or other oxidizer presence)
è Dimensions of the metal surface in contact with conductive
electrolyte.
(important! Water level on separators and oil tank internals)
n With the parameters is possible to design the system:
è which technique (sacrificial or impressed)
è anode selection (Al, Mg, Zn, Ti or Fe-Si-Cr)
è anode quantity (related to the required current)
è anode distribution (related to the disposition of the surface to
protect)
è current system design (only for impressed current)
è Insulation kits and resistance bonds disposition
116
CATHODIC PROTECTION
n Typical applications
è Underground and submerged steel surfaces (may be
required by law).
l
l
l
l
Bottom tanks
Underground and submerged Pipelines
Jacket on offshore structures
underground and submerged steel reinforced concrete
structures
è Low temperature corrosion on the process side (cost
evaluation).
l Water tanks
is preferable to cathodically protect internally lined surfaces
l Water boxes (channels) of Thermal exchangers
CP avoids cladding in Cu-Ni alloys in seawater exchangers
l Water-oil separators
CP avoids the use of stainless steel or ensure lower
maintenance of internal lining
117
MATERIAL SELECTION AND
CORROSION CONTROL IN
REFINERY UNITS
MATERIAL SELECTION AND CORROSION CONTROL IN REFINERY UNITS
n DESALTER
n ATMOSPHERIC DISTILLATION UNIT
n VACUUM DISTILLATION UNIT
n AMINE UNIT
n HYDRODESULPHURIZATION UNIT
n SOUR WATER STRIPPER UNIT
119
DESALTER
THE DESALTER CAN BE THE SOURCE OR THE SOLUTION OF
REFINERY’S PROBLEMS
120
DESALTER
TIPICAL CORROSION AND FOULING PROBLEMS
n Corrosion of water outlet lines (brine)
n Fouling of inlet heat exchangers (generally due to oxygen
and excessive temperature)
n Remaining problems with desalter aren’t problems in the
desalter itself (affect efficiency and downstream corrosion)
121
DESALTER - OPERATING GUIDELINES
n Principal variables (by UOP)
è wash water (4-10%)
è Settling time (30-45min)
è Temperature (90-150°C, high enough to dissolve sediments
and salts)
è Desalting chemicals (0.25 - 1 pint for 1000 barrels)
è Alternating electric field
è Valve
è ∆P (7-15 psig)
è Level
n TARGET: DESALT TO LESS THAN 2 LBS/THOUSAND BARREL (PTB)
n Stripped Water should be used as wash water
122
DESALTER - OPERATING GUIDELINES
123
TEMPERATURE
n Increasing temperature reduces viscosity and reduces settling time
n Increasing temperature increases water solubility and water
(including dissolved salt) carry over
n Keep inlet heat exchangers below 150 °C
è Reduce corrosion rates in exchangers
è Reduce fouling in exchangers (minimizing salt precipitation)
ATMOSPHERIC DISTILLATION UNIT
124
ATMOSPHERIC DISTILLATION UNIT
TYPICAL CORROSION AND
FOULING PROBLEMS
n HCl corrosion in the OVHD
system
èAmmonium Chloride
èAmmonium Bisulfide
n High
temperature
sulfur
corrosion
n Naphtenic acid corrosion
n Asphaltine/wax/polymer
fouling
n PASCC (300 series SS)
n Wet hydrogen sulphide
125
ATMOSPHERIC DISTILLATION UNIT
METALLURGY
Use Chrome alloy (solid or lining for high Cr %) for sulfur
resistance (according to McConomy curves) es. 1.25 Cr, 2.25Cr, 5
Cr, 9Cr, 12Cr in the bottom section of CDU tower and in the hot
side of the heating train
n Use Monel for HCl resistance in the top section of tower (for
cladding and trays) and in the OVHD accumulator if
condensation is expected
n Use 90-10 Cu-Ni for Chloride resistance in the desalter brine
n If Naphtenic acid are an issue (Note: check TAN number in cuts)
è ALL 5 - 9 - 12Cr change to 317 or 316 with 2.5% min Mo (see
also T and TAN)
è Carbon steel in gas oil cut may also change to 317 or 316 with
2.5% min Mo
è Must guard against PASCC of austenitic SS
126
ATMOSPHERIC DISTILLATION UNIT - MSD
127
NOTE: The indicated selection is not a guideline; it indicates only a
possible choice among several solutions as a function of process
conditions, corrosion mechanisms involved, lifetime and Prj requirements
ATMOSPHERIC DISTILLATION UNIT - OPERATING GUIDELINES
128
CAUSTIC INJECTION
n Inject caustic if necessary to reduce chlorides in OVHD or to
reduce TAN
è Use fresh 2-3% caustic
è Inject no more than 4 PTB
è Inject to crude no hotter than 150 °C
è Inject at least 5 feet upstream of equipment
è and as close to desalter downstream
as possible
è Inject using a quill
TAIL WATER pH
Injection Quills
n Operate between pH 5.5- 6.5 in tail water
n Use a online pH meter
n Automate control of corrosion inhibitor injection
n Keep pH meter clean (filming amine, used as inhibitor, can dirty the
instrument)
ATMOSPHERIC DISTILLATION UNIT - OPERATING GUIDELINES
WASH WATER IN OVERHEAD SYSTEM
n 20% of injected water not vaporized
n water quality not critical, can recirculate
DEW POINT
n Run top of tower above dew point
è Watch for “shock condensation” at point of recycle water inlet
CORROSION INHIBITOR
n Use corrosion inhibitor in the overhead line
n May need to inject neutralizer and film former separately
129
VACUUM DISTILLATION UNIT
130
VACUUM DISTILLATION UNIT
TYPICAL CORROSION AND
FOULING PROBLEMS
n H2S, CO2 corrosion in the
OVHD system
n High temperature sulfur
corrosion
wherever
temperature exceeds 260°C
n Naphtenic acid corrosion
especially in heater outlet
and transfer piping
n Asphaltine/wax fouling
n Polythionic acid SCC (300
series SS)
131
VACUUM DISTILLATION UNIT
METALLURGY
n Problem: traces of H2S, CO2, HCl in OVHD system
è SOLUTION: use MONEL mesh for demister
n Problem: traces of corrodents in Vacuum ejector
è SOLUTION: use 316 internals
n Problem: high temperature sulphur corrosion in bottom section of
tower and in the heating train
è SOLUTION: use chrome alloy (solid or lining for high Cr %)
according to McConomy curves
n Problem: Naphtenic acid corrosion (for cuts with TAN>0.5)
è ALL 5 - 9 - 12Cr change to 317 or 316 with 2.5% min Mo
n Problem: Polythionic acid SCC for sensitized material
è follow the recommendation listed in NACE RP 0170
132
VACUUM DISTILLATION UNIT - MSD
133
NOTE: The indicated selection is not a guideline; it indicates only a
possible choice among several solutions as a function of process
conditions, corrosion mechanisms involved, lifetime and Prj requirements
AMINE UNIT
134
AMINE UNIT
n
n
n
n
TYPICAL CORROSION AND FOULING PROBLEMS
Tendency for corrosion varies with amine used, concentration and
loading
Acid gas corrosion
è H2S, CO2
è Letdown valve into stripper
è Overhead of stripper
Heat stable amine salts (stronger than H2S)
è Not stripped by heat in stripper
è Inorganics (Cl-,SO4=, CN -, SO2)
l Contaminants in feed
è Organics (formic, acetic, oxalic)
l Feed+oxygen
l Pump seals, make up water
è Areas: stripper bottom, reboiler, hot lean amine pipe
Thermal degradation of amines
è forms corrosive, acid species (especially in presence of oxygen)
135
AMINE UNIT
136
METALLURGY
n Problem: Amine stress corrosion cracking and hydrogen damage
è SOLUTION: PWHT (see also amine SCC) and use killed carbon
steel
n Problem: Acid gas corrosion (Letdown valve/piping into stripper
and Overhead of stripper)
è SOLUTION: use SS (304 or 316)
n Problem: H2S, CO2in OVHD system
è SOLUTION: use SS for tube condenser and OVHD accumulator
(or CS HIC resistant)
n Problem: sour water in the reflux pump
è SOLUTION: use SS or duplex (as suggested by API 610)
AMINE UNIT - MSD
137
NOTE: The indicated selection is not a guideline; it indicates only a
possible choice among several solutions as a function of process
conditions, corrosion mechanisms involved, lifetime and Prj requirements
AMINE UNIT - OPERATING GUIDELINE
n Limit amine temperature to 130 °F
èReboiler steam less than 4.5 bar
n Avoid acid gas flashing
èUpgrade
unavoidable
metallurgy
if
n Keep out oxygen from the system
n Control fluids velocity
n Filter
è Typically 10-20 µm (smaller may help, i.e. 2 in series 15µ
µm-5µ
µm)
è Partially filtration (10-15%) may be sufficient
è Carbon filter to remove hydrocarbon and reduce fouling
n Problems come from operating at maximum
è Amine concentration
è Circulation rate
è Rich amine loading
138
HYDROTREATER
139
HYDROTREATER
TYPICAL CORROSION AND FOULING PROBLEMS
n Rust from tankage
è oxygen in tank/transport
è Plugs reactor bed
n High temperature sulphur attack (sulphidation)
n High temperature hydrogen attack (HTHA)
n ammonium chloride in hydrogen recycle gas
n ammonium bisulphide
è Reactor Effluent Air Cooler (REAC)
n Wet hydrogen sulphide
n PASCC
140
HYDROTREATER
141
METALLURGY
n Problem: Sulphidation and HTHA on reactor feed (generally from
heater), reactor and effluent piping and exchangers
è SOLUTION: use Austenitic SS (321 or 347). Use Chrome alloy for
base material in case of cladded solution
n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S on
REAC, piping and accumulator
è SOLUTION: use wash water and/or upgrade material to Incoloy
825, Inconel 625 or Ti. Austenitic 316 may be good to clad water
phase on accumulator. CS is also possible with stringent
velocity limits and monitoring
n Problem: Polythionic acid SCC for sensitized material
è follow the recommendation listed in NACE RP 0170
HYDROTREATER - MSD
142
NOTE: The indicated selection is not a guideline; it indicates only a
possible choice among several solutions as a function of process
conditions, corrosion mechanisms involved, lifetime and Prj requirements
HYDROTREATER - OPERATING GUIDELINE
n Oxygen in feed (rust in tanks and polymerization fouling)
è Gas blanket tankage
l Nitrogen best
l Natural gas may have air in it
l Fuel gas good
è Better bypass tankage section
n Wash water
è can be continuous (better)
or discontinuous
è Use balanced exchanger
è 20% of injected water not vaporized
è Velocity between 2.5 and 6m/s
(9 for alloy)
è Foul water < 8% NH4HS
143
SOUR WATER STRIPPER
144
SOUR WATER STRIPPER
TYPICAL CORROSION AND FOULING PROBLEMS
n ammonium chloride
n ammonium bisulphide
è Reactor Effluent Air Cooler (REAC)
n Wet hydrogen sulphide
n Hydrogen damage
145
SOUR WATER STRIPPER
METALLURGY
n Problem: Sulfide Stress Cracking
è SOLUTION: Apply requirements of NACE MR0103 where
necessary
n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S on
REAC, piping and accumulator and reflux pump. Erosion corrosion
on pump
è SOLUTION:
l Use intermittent wash water on REAC and upgrade material to Ti.
l Use SS pipe (304 or 316 if chloride are expected) Maintain stream
velocity below 15 m/s on piping.
l Austenitic 316 may be good to clad accumulator
l Use Hastelloy C (or alloy 20) on reflux pump to withstand corrosion
and erosion-corrosion
n Problem: Hydrogen damage on feed surge drum
è SOLUTION: Use CS HIC resistant or CS SS cladded or lined CS
(+CP)
146
SOUR WATER STRIPPER
147
METALLURGY
n Problem: Wet H2S Corrosion, Acid gas on tube bottom feed
exchanger, stripping column upper portion and inlet (after valve)
è SOLUTION: Use solid SS (304 or 316 if chloride are expected) or
cladding solution.
n Problem: Galvanic corrosion exchanger, stripping column upper
portion and inlet (after valve)
è SOLUTION: Use solid SS (304 or 316 if chloride are expected) or
cladding solution.
n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S
Erosion corrosion on charge sour water pump
è SOLUTION:
l Use Duplex or Superduplex SS to withstand corrosion and erosioncorrosion
SOUR WATER STRIPPER - MSD
148
NOTE: The indicated selection is not a guideline; it indicates only a
possible choice among several solutions as a function of process
conditions, corrosion mechanisms involved, lifetime and Prj requirements