1
API 571 for Inspectors –
“Damage Mechanisms Affecting Fixed Equipment
in the Refining Industry”
2
Presenter: Charlie Buscemi
20 Years experience in the Petrochemical Industry Experience in corrosion, materials selection, research and development, and failure analysisChevron, Connexsys, Stress Engineering Services (SES, Inc.)Currently Staff Consultant, SES, Inc. -New Orleans office
3
API 571 for InspectorsTo Introduce inspectors to the general contents of API 571 To describe some common damage
mechanismsSources and References:–
API 571 and Other API Standards
–
NACE Recommended Practices–
ASM Metals Handbook
4 4
Common Alloys Used in the
Petrochemical Industry
5 5
Carbon & Low-Alloy Steels
Carbon steel: all purposeHIC-resistant CS: wet H2
S cracking resistance1-1/4Cr-1/2Mo and 2-1/4Cr-1Mo: high-
temperature strength, creep resistance, HTHA resistance
5Cr-1/2Mo, 7Cr-1Mo, 9Cr-1Mo: same as above, plus high-temperature sulfidation
resistance
(common furnace tube alloys)12Cr (Type 410 SS): for high-temp sulfidation
resistance (cladding & internals)
6 6
Stainless SteelsChromium SS:•
Type 410 (12% Cr), Type 430 (17% Cr)
•
For high-temp sulfidation
in non-hydrogen environments (esp. atmospheric Crude Units, vacuum units)
Austenitic SS:•
“300-series”: Types 304/L, 316/L, 317, 321, 347
•
For H2
/H2
S environments (cladding, piping, internals in hydrocrackers, hydrotreaters)
•
High-temperature services (FCC units)•
Heat exchanger shells, tubesheets, and tubes
•
Furnace tubes
7 7
Specialty Alloys –
Aqueous Corrosion
•
Duplex SS (22Cr-5Ni-3Mo) for better SCC and pitting resistance than 300-series SS (resists SCC to 200°-250°F, instead of 140°F)
•
Alloy 20 (29Cr-20Ni) for SCC resistance, also for sulfuric acid resistance in turbulent locations, especially pumps
•
Monel
400 (for HCl
acid resistance in Crude Unit distillation towers and overhead systems: trays, overhead piping, cladding)
•
Hastelloy
B, C, C-22, C-276 for acid corrosion
8 8
Alloys for High-Temperature Corrosion & Strength
•
Incoloy
800, 800H, 825 (35Ni-20Cr): for high-temperature corrosion and high-Temp strength to 1650°F
•
Type 309, 310SS (25Cr, 12-20 Ni): high Cr concentration for oxidation resistance above 1600°F (tube hangers, refractory anchors)
•
Haynes, RA, HP, HK cast alloys (Co, W, Mo additions) for extreme high-temperature oxidation and strength (tubes, hangers, hydrogen manufacturing)
9 9
Heat Exchanger Alloys
•
Admiralty brass (cooling water exchangers)•
Copper-Nickel (90-10 Cu-Ni, 70-30 Cu-Ni): better resistance to cooling water corrosion, especially in brackish or high-velocity streams
•
Titanium (for heat exchanger tubes, especially in multi-corrosive locations, like Crude Unit overhead systems)
--
Specify Gr. 7, 12 for hydriding
resistance
10 10
API RP 571•
Section 1 –
Intro & Scope (2 pgs.)
•
Sec. 2 –
References (API, ASME, ASTM, NACE, etc.) (2 pgs.)
•
Sec. 3 –
Terms & Abbreviations (4 pgs.)•
Sec. 4 –
Damage Mechanisms --
All
Industries (44 mechs., 152 pgs)•
Sec. 5 –
Damage Mechanisms --
Refining industry (18 mechs., 61 pgs)•
PFD’s
(14 pgs.)
11
Example of a PFD Denoted with Damage Mechanisms
12 12
Section 4.2
•
Mechanical and Metallurgical Failure Mechanisms
•
All Industries
(Thermal effects, aging, embrittlement, creep & stress rupture, fatigue, erosion)
13 13
4.2.2: Spheroidization•
Changes in CS and low-alloy microstructure after long-term exposure at 850°-1400°F
•
Carbide coarsening results in a decrease in high-temperature tensile and creep strength
•
CS above ~ 800-850°F•
9Cr-1Mo above ~ 1000°F
14 14
4.2.2: Spheroidization
15 15
4.2.2: Spheroidization
•
Occurs in:Furnace tubes, hot-wall piping and equipment, FCC, coker, and cat reformer units, where temperature exceeds 850°F
•
Usually a problem only at high stresses (stress concentrations) since strength typically drops by 25-30% max.
16 16
4.2.2: Spheroidization
•
Inspection techniques:--
Field Metallurgical Replication (FMR, “replicas”)
--
Field hardness testing (Brinell)--
remove samples for lab analysis
17 17
4.2.5: 885ºF Embrittlement
•
Long-term exposure of duplex and ferritic
stainless steels (12Cr Types
405, 410, Duplex 2205) at 600◦-1000◦F •
Loss of ambient temperature ductility (on shutdowns)
•
Ductility sufficient at operating temperature
18 18
4.2.5: 885◦F Embrittlement
•
Not pressure-containing components•
These alloys are used only for internals in the susceptible temperature range (cladding, trays, etc. in FCC, coker, and Crude towers)
•
May result in difficulty welding or straightening affected components
19 19
4.2.5: 885◦F Embrittlement
•
Inspection techniques:
--
Field hardness testing (Brinell)--
Bend test
--
Charpy
impact testing
20 20
4.2.6: Sigma Phase Embrittlement
•
Occurs in 300-series stainless steels after long-term exposure to 1000°-
1700°F•
Hard, brittle intermetallic
phases are
formed from the ferrite phase •
321SS & 347SS are more susceptible than 304SS
21 21
4.2.6: Sigma Phase Embrittlement
•
Occurs in 3xx SS in very high temperature services:
--
FCC regenerator internals, --
catalyst slide valves,
--
hydrogen plant furnace tubes--
styrene & other chemical plants
22 22
4.2.6: Prevention of Sigma Formation
•
Specify maximum ferrite content of 3-11% in the finished weld
•
Limit the use of susceptible alloys in the 1100°-1700°F temperature range
•
Use Ferrite scope, DeLong
diagram, Schaeffler diagram to get proper ferrite content in the weld
23
4.2.6: Schaeffler
Diagram
23
24 24
4.2.6: Sigma Phase Embrittlement•
Before fabrication:
--
control ferrite (ferrite scope, Schaefler and DeLong
diagrams)
•
Inspection techniques:--
FMR
--
remove samples for lab analysis --
Charpy
impact test
•
To find & size cracks:--
dye penetrant
(PT); shear wave UT
25 25
4.2.8: Creep & Stress Rupture
26 26
4.2.8: Creep & Stress Rupture
•
Occurs at elevated temperatures (see API 530):
CS: 700°F5Cr: 800-850°F9Cr: 800-850°F300-series SS: 900°F +
27 27
Creep in a CO boiler tube•
Normal Top
: 520°-660°F•
Took 8 years to fail (probably operated at 750-800°F for some time)
28 28
Creep Voids and Fissures at 500X
29
4.2.8 –
Larson Miller Curves – API 530
30 30
4.2.8: Stages of Creep
31 31
4.2.8: Creep & Stress Rupture
•
Affects furnace tubes, boiler tubes, hangers
•
Internal creep voids grow and link together to form internal fissures and cracks
•
Damage can be detected at 1/3 to 1/2 of creep life
•
Bulging, go/no-go when expansion reaches 3-8%, depending on alloy
32 32
4.2.8: Creep & Stress Rupture•
Inspection techniques:
--
Visual inspection for bulges--
Go/no-go gauging
--
Strapping (diametral
expansion)--
Radiography (RT)
--
Ultrasonic thickness testing (UT)--
Field replication (FMR)
•
Monitor with TI’s
and infrared (IR) scans
33 33
4.2.9: Thermal Fatigue
•
All metals can undergo thermal fatigue
•
Cyclic stress due to alternating temperatures results in crack formation and propagation
•
Typically forms wedge-shaped or carrot-shaped, scale-filled cracks
34 34
4.2.9: Thermal FatigueWedge-Shaped, Oxide-Filled Cracks
35 35
4.2.9: Thermal Fatigue•
Where hot and cold streams combine (injection points)
•
Boiler tubes, steam generating equipment (quenching of hot tubes), coke drums
•
Coke drum girth welds, head-to- shell welds, skirt welds
•
Smooth out weld contours
36 36
4.2.9: Thermal Fatigue
•
Inspection techniques:
--
Visual inspection +--
Dye penetrant
(PT) of stainless steel
--
Wet fluorescent magnetic particle testing (WFMT) of carbon
steels and Cr-Mo alloys--
External SWUT at attachment welds
37 37
4.2.16: Mechanical Fatigue
•
Due to cyclic stress•
Typical crack initiation sites: pits, sharp corners, thread roots, grooves, notches
•
Mitigation: smooth out transitions, blend weld crowns and notches, reduce stress, increase thickness, tensile strength
38 38
4.2.16: Mechanical Fatigue
•
Characteristic “beach marks” or “clamshell marks”
•
Marks are the start-and-stop locations of crack propagation
•
Clamshell marks are caused by exposure to corrosion, atmosphere, oxidation, thermal tinting
39 39
4.2.16: Mechanical FatigueCrack origin at a major transition
in shaft thickness
40 40
4.2.16: Mechanical Fatigue
41
4.2.16: Mechanical Fatigue
41
42 42
4.2.16: Mechanical Fatigue
•
For some metals, an “endurance limit” exists (CS, low-alloy steels, titanium)
•
Below a particular stress, fatigue cracking will never occur
•
Endurance limit is usually nearly half the tensile strength (UTS)
43 43
4.2.16: Mechanical Fatigue
•
For other metals, no limit exists (stainless steels, non-ferrous alloys)
•
Fatigue cracking will eventually occur
•
The number of cycles required is a function of the alternating stress
44 44
Mechanical Fatigue Life
(0.10)0.000.100.200.300.400.500.600.700.80
0 10 20 30 40 50 60 70 80 90 98
Fatigue Life Expended (%)
Leng
th o
f Cra
ck in
.
45 45
4.2.16: Mechanical Fatigue
•
Inspection techniques:
--
Visual inspection at stress risers
--
Check for oscillation, vibration--
Dye penetrant
(PT)
--
Wet fluorescent magnetic particle testing (WFMT)
--
Shear wave UT
46 46
4.2.17: Vibration Fatigue•
Susceptible equipment:
--
Piping attached to reciprocating and rotating equipment
--
Pressure letdown valves and associated piping
--
Relief valves--
Piping branch connections
--
Heat exchanger tubes (esp. w/ thin-walled tubes)
47 47
Section 4.3
•
Uniform or Localized Loss of Thickness
•
All Industries•
Aqueous Corrosion
48 48
4.3.1: Galvanic Corrosion
•
Electrical current flowing between dissimilar metals in an electrolyte (wet corrosive environment)
•
Battery cell•
Preferential, accelerated attack of the more active metal (anode)
•
Dissimilar joints located in water (cooling water heat exchangers)
49 49
4.3.1: Galvanic Corrosion
CSSS
Electrolyte
MgCS
Electrolyte
50 50
Inspection Techniques for:
4.3.1 Galvanic Corrosion4.3.2 Atmospheric Corrosion
--
Visual inspection--
Ultrasonic thickness testing
51 51
4.3.3: Corrosion Under Insulation (CUI)
•
Rapid corrosion of carbon steels and low- alloy steels under wet insulation
•
Stainless steels can pit or crack from chloride SCC
•
Sweating equipment or rain water ingress •
Local corrosion at penetrations in insulation, jacketing at pipe supports, leaking steam tracing where moisture penetrates the insulation
52 52
4.3.3: Corrosion Under Insulation (CUI)
•
Chlorides in insulation worsen CUI•
Worse downwind of cooling towers
•
Use chloride-free insulation•
Coat/paint susceptible vessels
•
Make sure weather jacketing is in good condition
53 53
4.3.3: Corrosion Under Insulation (CUI)
•
Corrosion techniques:
--
visual inspection under insulation--
guided wave UT to find general metal loss
--
radiography (RT) of small bore piping
--
strip insulation and UT thickness
54 54
4.3.4: Cooling Water Corrosion
•
Oxygen scavengers, pH control, fluid velocity, temperature monitoring
•
Velocity too low (CS < 3 fps): solids deposit on tube walls and lead to underdeposit
pitting
•
Velocity too high (brass > 3 fps): erosion-corrosion
•
Upgrade to Cu-Ni, duplex SS, titanium, epoxy coated tubes
55 55
4.3.4: Cooling Water CorrosionSaltwater vs Carbon Steel and Alloys
0
10
20
30
40
50
60
70
80
90
0 50 100 150 200 250Temperature F
Cor
rosi
on R
ate
(mpy
)…
CS Adm. Brass 70-30 Cu-Ni Titanium
56 56
4.3.4: Cooling Water Corrosion
•
Inspection techniques:
--
Visual inspection at tube ends
--
Eddy current (EC) inspection --
IRIS inspection of magnetic tubes
--
Split sample tube & send to lab--
Monitor water chemistry
57 57
4.3.8: Microbiologically Induced Corrosion (MIC)
•
Bacteria in cooling water systems, firewater systems, heat exchangers, pressure vessels, storage tanks, oil and gas pipelines, wells, etc.
•
Typical of MIC is the creation of thick growths, also known as tubercles
•
Tubercles concentrate acids and other waste products at the metal surface
•
Underdeposit
corrosion, fouling, loss of thermal conductivity in heat exchangers
58 58
4.3.8: Microbiologically Induced Corrosion (MIC)
•
Surface pits under tubercles; carbon steel
•
Pits in cross-section; Type 316 stainless steel
59 59
Anaerobic Sulfate Reducing Bacteria (ASRB) Potentially the most common & destructive bacteria group. ASRB reduce
sulfates in the water, soil or oil, to H2 S which corrodes the steel under the deposit
Acid Producing Bacteria (APB)Capable of producing organic and inorganic acids as well as producing nutrients for ASRB. APB metabolize sulfur in the water, soil or oil, to
sulfurous acid which corrodes steel under the deposit.
Iron-related bacteria (IRB)Create reactions that support SRB and other MIC bacteria. Form tubercles
that concentrate corrosive species
Slime-producing bacteria (SPB)Live in conjunction with other MIC-producing bacteria (APB, SRB, and IRB).
Can from a bridge from aerobic to anaerobic conditions.
4.3.8: MIC - Types of Bacteria
60 60
4.3.8: Microbiologically Induced Corrosion (MIC)
•
Bacteria in cooling water systems, firewater systems, heat exchangers, pressure vessels, storage tanks, oil and gas pipelines, wells, etc.
•
Typical of MIC is the creation of thick growths, also known as tubercles that concentrate acids and waste products at the metal surface
•
Underdeposit
corrosion, fouling, loss of thermal conductivity in heat exchangers
•
See NACE TM-0194
61 61
4.3.8: MIC –
Inspection•
Check for fouling of HX bundles, tank & drum bottoms, firewater & stagnant piping
•
Visually inspect for tubercles•
Foul-smelling liquids may indicate MIC
•
Confirm MIC with field test kits. Biological Activity Reaction Test (BART)
•
Use biocides
62 62
Section 4.4
•
High-Temperature Corrosion•
Above 400°F
•
All Industries
63 63
4.4.1: High-Temp Oxidation
•
Add chromium to increase oxidation resistance:
CS: 10 mpy rate at 1050°F 2-1/4Cr: at 1100°F5-9 Cr: at 1200°-1250°F304SS: at 1550°FIncoloy 800/H: at 1700°FHK, HP: > 1900°F
64 64
4.4.1: Oxidation Rates
65 65
4.4.1: High-Temp. Oxidation
•
Furnace tubes & hangers, burners, refractory anchors
•
Can be non-uniform on tubes due to flame impingement
66 66
4.4.1: High-Temp. Oxidation
•
Inspection Techniques:
--
Use TIs
& IR thermography
while in service to determine the locations of hot spots
--
Visual inspection (look for thick scale)--
UT thickness gauging
67 67
4.4.2: High-Temp Sulfidation
•
Reaction of metals with hydrogen sulfide
Fe + H2
S FeS + H2
FeS
+ H2
S FeS2
+ H2
•
Sulfur compounds in crude oil decompose to H2
S •
H2
S content determines crude corrosivity
68 68
4.4.2: High-Temp Sulfidation
•
Crude units, vacuum units •
>1 ppm
H2
S with no hydrogen•
Upstream of hydrocrackers
and
hydrotreaters•
Extremely sensitive to temperature
•
Add Cr to increase sulfidation resistance
69 69
4.4.2: High-Temp Sulfidation
•
CS and low-chrome: above ~500°F•
5 Cr: above ~ 650°F
•
12Cr and 300-series SS: practically immune
Used for: Cladding, internals, trays
70 70
4.4.2: Sulfidation: Vacuum Column Bottoms Pump
71 71
4.4.2: Sulfidation: Vacuum Column Bottoms Pump
72 72
4.4.2: High-Temp. Sulfidation
•
Inspection Techniques:
--
TIs
& IR thermography
while in service
--
Visual inspection--
UT thickness gauging
--
Quest Tru-Tech FTIS of furnace tubes--
PMI (materials identification)
7373
4.4.2: Sulfidation
– NACE Publication 34103
74 74
Section 4.5
•
Environment –
Assisted Cracking (SCC)
•
All Industries
75 75
4.5: Stress Corrosion Cracking (SCC)
Depends on environment, material, and temperature. Avoidance measures:
Change metallurgyStress relief; PWHTReduce temperatureUse coatingsReduce stressDesign changes: avoid wet/dry conditions
76 76
4.5.1: Chloride SCC
•
Aqueous mechanism•
Requires water with >50 ppm
Cl-
•
Above ~130°F in 300-series SS•
Above 250-300°F in Duplex SS (Alloy 2205)
•
Branched cracking at welds, bends•
Areas with high residual stress: welds, cold formed bends, bellows, expanded tubes
77 77
Transgranular, surface initiated cracks
In sensitized stainless steels, cracking can be intergranular (along grain boundaries)
4.5.1: Chloride SCC
78 78
Sensitization of 300-Series SS
79 79
4.5.1: Chloride SCC Effect of Temperature and Chloride
Concentration
80 80
4.5.1: Chloride SCC
•
Susceptible: 300-series SS heat exchanger tubes, vessels, piping, cladding, furnace tubes (on shutdowns)
•
Insulation for 300-series SS tanks, piping, & vessels must be chloride-free
•
May be external due to chlorides in atmosphere, rain water, or insulating materials
81 81
4.5.1: Chloride Content of Some Materials
82 82
4.5.1: Chloride SCC
•
Inspection Techniques:--
On-line acoustic emission (AE)
--
Eddy current (EC)--
Dye penetrant
(PT)
--
Visual inspection at tube ends--
Shear wave UT to size cracks
--
split tubes and inspect ID
83 83
4.5.3: Caustic SCC•
Steels and nickel alloys are susceptible
•
Must have liquid water w/ caustic >50 ppm
•
Temperature >120ºF
•
pH 8-14
•
Tensile stress >25% of YS
•
Non-PWHT’d
welds, bends are especially susceptible
84 84
Intergranular
cracking along grain boundaries4.5.3: Caustic SCC
Caustic Cracking in Carbon SteelCaustic Cracking in 316SS Steel
85 85
4.5.3: Caustic SCC•
Sources: boiler feed water, injection to neutralize acids in crude feed and CU overhead
•
Results in branched cracking•
Can be intergranular, transgranular, or mixed
•
Stress relieve carbon steel or upgrade to nickel alloys
86 86
4.5.3: Caustic SCC•
300-series stainless steels can crack in caustic above about 230°F
•
Due to chlorides in caustic, 300-series SS is generally not used as an upgrade
• Typical upgrade is Monel
above
180°-230°F
87 87
4.5.3: Caustic SCC
8888
4.5.3: Caustic SCC of Carbon Steel –
NACE SP 0403
89 89
4.5.3: Caustic SCC
•
Inspection Techniques:
--
Visual inspection +
--
PT, WFMT
--
Shear wave UT to size cracks
--
Eddy current (EC) and IRIS of heat exchanger tubes
90 90
Section 5.1.1.1:
• Uniform or Localized Loss of Thickness
• Refining Industry
91 91
5.1.1.1: Amine
Corrosion
• Amines are used to remove corrosive acid gases (H2
S & CO2
) from process gases and liquids
•
Amines can contain acid gases and corrosive degradation products
•
Contaminants include abrasive solids, salts, process chemicals
92 92
5.1.1.1: Amine
Corrosion•
Localized metal loss, especially in high turbulence areas
•
Caused by flashing of acid gases (H2S and CO2)
•
High acid gas loading and salt levels can lead to hydrogen blistering & HIC
•
Can cause SCC in non-post weld heat treated equipment
•
Rich amine is more corrosive
93 93
5.1.1.1: Amine
Corrosion
94 94
5.1.1.1: Amine Corrosion
•
Design for 6 fps max. velocity on rich side, 20 fps max. on lean side
•
Decrease turbulence
•
Clad vessels with 300-series stainless steels
•
Upgrade piping, valves, tees to 304L, 316L stainless steel
95 95
5.1.1.1: Amine Corrosion
Highly susceptible areas:
•
Amine regenerators, reboilers, and associated piping where temperature exceeds 200°F
•
Rich amine piping•
High velocity, turbulent streams with acid gas flashing (pump discharge spools, downstream of letdown valves)
96 96
5.1.1.1: Amine Corrosion
•
Visual inspection•
Automatic or grid ultrasonic (UT)
•
radiography (RT) for general metal loss•
Installation of corrosion coupons and electrical resistance (ER) probes
•
Size stress-corrosion cracks with dye penetrant
(PT) and wet fluorescent
magnetic particle testing (WFMT)
97 97
5.1.1.2: Ammonium Bisulfide Corrosion
•
Aqueous corrosion mechanism where H2
S and NH3
exist simultaneously (NH3
+H2
S = NH4
HS)•
Hydrotreater
and FCC overhead systems
(especially effluent air coolers and inlet/ outlet piping
•
Amine regenerator overhead systems•
Sour water stripper overhead systems
98 98
5.1.1.2: Ammonium Bisulfide Corrosion
•
Causes erosion-corrosion of carbon steel at velocity >10-20 fps and in turbulent locations
•
Causes deep pitting, corrosion in concentrated streams (NH4
HS conc. > 20-30 wt.%)
99 99
5.1.1.2: Ammonium Bisulfide Corrosion
Mitigation:•
Reduce velocity and turbulence
•
Clad severe areas w/ 300-series SS•
Use Incoloy
825 for effluent air cooler
headers & piping
100 100
5.1.1.2: Ammonium Bisulfide Corrosion
•
Inspection techniques:--
Locally washed out, thinned areas are easy to miss
--
Frequent AUT or grid UT at piping bends, valves, reducers, etc.
--
Radiography (RT)--
EC, IRIS of air cooler tubes
101 101
5.1.1.4: HCl
Corrosion•
Tops of atmospheric and vacuum towers
•
Atmospheric & vacuum crude distillation unit overhead streams
•
Acid is the result of hydrolysis of magnesium and calcium chloride salts in crude oils
•
Desalting can reduce HCl
formation
• Corrosion occurs where water condenses
•
Upgrades: Monel
trays and cladding
102 102
5.1.1.4: HCl
Corrosion
•
General wasting & washed out appearance•
Severe thinning with no scale
•
Corrosion rate can exceed an inch per year (1000 mpy) on carbon steel at elevated temperatures
•
Monel
has been successful as trays at top of distillation tower and in O/H vapor line
103 103
5.1.1.4: HCl
Corrosion
104 104
5.1.1.4: HCl
Corrosion•
Inspection techniques:--
Visual inspection of trays and O/H lines
--
Automatic UT or grid UT, radiography (RT) of overhead streams and known trouble spots
--
Corrosion probes (ER, FSM) and coupons
--
Hydrogen flux, Fe++, Cl-
monitoring
105 105
5.1.1.5: H2
/H2
S Corrosion
•
Occurs in the presence of hot H2
and H2
S simultaneously•
Corrosion rate depends on temperature and partial pressure of H2
S•
Usually uniform metal loss
•
H2
results in porous non-protective iron sulfide scale
106 106
5.1.1.5: H2
/H2
S Corrosion
•
CS-9Cr: significant corrosion > 500°-550°F
•
12 Cr steel (410SS): > 700°-800°F •
300-series SS: > 900°-1000°F
•
Hydrotreaters, FCC’s•
300-series SS for reactor cladding, internals, and hot piping (> 750°F)
107 107
5.1.1.5: H2
/H2
S Corrosion – Corrosion
Rates
108 108
5.1.1.5: H2
/H2
S Corrosion –
•
Unlike high-temperature sulfidation
in crude units, cokers, vac
units (in the
absence of hyrogen)•
High-Temp Sulfidation: additions of Cr alone add corrosion resistance
•
H2
/H2
S Corrosion: Cr alone is not beneficial. Requires upgrade to 304, 316 SS
109 109
5.1.1.5: H2
/H2
S Corrosion –
110 110
5.1.1.5: H2
/H2
S Corrosion
•
Inspection Techniques:--
Visual inspection +
--
Ultrasonic thickness (UT)--
Radiography (RT)
111111
5.1.2.3: SCC Resistant Materials – NACE MR 0103
112 112
5.1.1.11: Sulfuric Acid Corrosion
•
Sulfuric acid alkylation
plants•
Can result in washout and severe thinning of carbon steel
•
CS cannot be used for weak acid•
Refineries use carbon steel extensively for strong acid concentrations (95-
100%) at near ambient temperatures•
Can require large corrosion allowances
113 113
5.1.1.11: Sulfuric Acid Corrosion
•
Corrosion is velocity and turbulence related localized
•
Velocity must be <3 fps for CS•
CS corrosion rate < 50 mpy
if acid
concentration > 65%, T <125°F, velocity < 3 fps
•
Alloy 20 (29Cr-20Ni-3Mo) for pumps; 316SS for thin-wall piping
114 114
5.1.1.11: Sulfuric Acid Corrosion
Corrosion of Carbon Steel
115 115
5.1.1.11: Sulfuric Acid Corrosion
Corrosion of Alloy 20
116 116
5.1.1.11: Sulfuric Acid Corrosion
•
Inspection Techniques:
--
Automatic UT or grid UT, RT (esp. in hot or turbulent areas)
--
Visual inspection
--
Corrosion probes and coupons
117 117
Section 5.1.2•
Environment-Assisted Cracking
•
Refining Industry
118 118
5.1.2.3: Wet H2
S Cracking
•
Hydrogen Induced Cracking (HIC) --
hydrogen charging in the presence of sulfur
•
Stress-oriented HIC (SOHIC)•
Hydrogen blistering
•
Sulfide Stress Cracking (SSC) --
cracking of hard welds
119 119
5.1.2.3: Wet H2
S Cracking
120 120
5.1.2.3: Hydrogen Induced Cracking (HIC)
•
Occurs mostly in carbon steel plate and thick-walled piping
•
Where sour water is present:--
overhead equipment
--
separators & K.O. drums --
heat exchanger channels & shells
•
Mostly at ambient temperature, up to about 150°F
121121
Wet H2S Cracking in Distillation Unit Overhead Systems
122122
Examples of Hydrogen Blistering
123 123
Hydrogen Induced Cracking and Blistering
•
Sulfur poisons the “recombination” reaction
•
Ho
+ Ho
H2
gas
•
Hydrogen atoms are absorbed into the steel and form internal hydrogen blisters and cracks
124 124
HIC and Blistering
125 125
5.1.2.3: Hydrogen BlisteringBlisters on the ID surface of affected carbon steel
126 126
5.1.2.3: Wet H2
S Cracking -- Special Precautions
•
Blistered steel is irreversibly damaged •
If repairs are to be made to damaged steel, expect the steel to be hydrogen-
saturated and potentially embrittled•
Prior to repairs: consider hydrogen “bake out”
at > 400°F
127 127
5.1.2.3: Sulfide Stress Cracking
•
Cracking of hard metals and weld HAZs•
Maintain weld hardness below BHN 200 for CS, BHN 215 for low-alloy steels
•
Valve trim, bolting <Rc
22, YS <90 ksi•
welds, 12Cr trim, B7 bolting susceptible
•
Refer to NACE MR-0175•
Use B7M bolts
128 128
5.1.2.3: Sulfide Stress Cracking (SSC)
129 129
5.1.2.3: Wet H2
S Cracking•
FCC Units --
fractionator
overhead
equipment, gas absorbers, compressors•
Hydrocrackers
& Hydrotreaters
–
valve
stems & trim, gas absorbers and compressors, cold separators
•
Sour water strippers –
upper sections of columns, overhead drums & exchangers
•
Crude unit overhead equipment•
Amine, acid gas units –
columns, drums,
exchanger shells
130 130
5.1.2.3: Avoiding Wet H2
S Cracking in Welds
•
PWHT welds to reduce weld hardness and residual stress
•
BHN 200 max. for carbon steel; BHN 215 max. for low-alloy steels
•
PWHT carbon steel at 1100°-1200°F (1 hr./inch, 1 hr. min.)
•
PWHT 1-1/4Cr & 2-1/4Cr steel at 1300°-1375°F
131 131
5.1.2.3: Wet H2
S Cracking•
Inspection:--
Visual inspection for blisters, cracks
--
Straight beam and shear wave UT can find internal blisters
--
Inspect welds, HAZs
for SSC with WFMT (no PT --
cracks can be tight)
--
Alternating current magnetic flux leakage (ACFM)
--
Radiography (RT)
132 132
5.1.3.1: High-Temperature Hydrogen Attack (HTHA)
•
In hot high-pressure hydrogen•
CS immune to ~450°F, depends on H2
pp•
Cr & Mo increase HTHA resistance(1-1/4Cr-1/2Mo, 2-1/4Cr-1Mo, 3Cr-1Mo)
•
Causes internal methane bubbles and fissures•
Reduces impact toughness; causes blisters
•
Can be very difficult to find; advanced inspection techniques
•
HTHA predicted by API 941 (Nelson Curves)
133 133
5.1.3.1: High Temperature Hydrogen Attack
•
Hydrogen in contact with steel at high temperature leads to decarburization and subsequent methane formation:
C(Fe)
+ 4H°
CH4 (gas)
•
Methane that forms internally in steels, result in fissures from high-pressure “bubbles”
on grain boundaries
•
Fissures result loss of fracture toughness, and potentially catastrophic brittle fractures
134 134
5.1.3.1: High-Temperature Hydrogen Attack
Hydrogen Attack
“Formation of Microfissures”
135 135
5.1.3.1: High-Temperature Hydrogen Attack in Carbon Steel
136 136
5.1.3.1: High-Temperature Hydrogen Attack
–
API 941
137 137
5.1.2.1: API 941 Limits for HTHA
138 138
5.1.3.1: HTHA Prevention
•
Cr & Mo additions improve resistance to HTHA
•
New equipment should be fabricated from HTHA- resistant materials for the design operating pressures
and temperatures (according to API 941 guidelines)
•
Existing equipment that does not meet API 941 guidelines should be removed from service or subject to concentrated frequent inspection
•
HTHA causes a loss in strength and fracture toughness and can result in brittle fracture. Equipment containing HTHA may not be fit for service
139 139
5.1.3.1: HTHA Inspection
•
Very difficult to find incipient attack•
May be more likely at spec breaks, in dead legs, in welds, HAZs
•
Must have an idea of where to look•
UT velocity ratio and backscatter
•
Focused beam shear wave
•
If in doubt, take a boat sample or replace suspected piping; downgrade PV’s
140
Questions ?
Please feel free to contact me:
Charlie Buscemi
Mobile: (504) 650-2427
Office: (504) 889-8440