1. 1
API 571 for Inspectors –
“Damage Mechanisms
Affecting Fixed Equipment
in the Refining Industry”
2. 2
Presenter: Charlie Buscemi
ƒ 20 Years experience in the Petrochemical
Industry
ƒ Experience in corrosion, materials selection,
research and development, and failure
analysis
ƒ Chevron, Connexsys, Stress Engineering
Services (SES, Inc.)
ƒ Currently Staff Consultant, SES, Inc. -
New Orleans office
3. 3
API 571 for Inspectors
ƒ To Introduce inspectors to the
general contents of API 571
ƒ To describe some common damage
mechanisms
ƒ Sources and References:
– API 571 and Other API Standards
– NACE Recommended Practices
– ASM Metals Handbook
5. 5 5
Carbon & Low-Alloy Steels
Carbon steel: all purpose
HIC-resistant CS: wet H2S cracking resistance
1-1/4Cr-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 6
Stainless Steels
Chromium 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/H2S environments (cladding, piping, internals in
hydrocrackers, hydrotreaters)
• High-temperature services (FCC units)
• Heat exchanger shells, tubesheets, and tubes
• Furnace tubes
7. 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 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 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 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.)
13. 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
15. 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 16
4.2.2: Spheroidization
• Inspection techniques:
-- Field Metallurgical Replication
(FMR, “replicas”)
-- Field hardness testing (Brinell)
-- remove samples for lab analysis
17. 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 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 19
4.2.5: 885◦F Embrittlement
• Inspection techniques:
-- Field hardness testing (Brinell)
-- Bend test
-- Charpy impact testing
20. 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 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 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
31. 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
33. 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
35. 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 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 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 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
42. 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 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
47. 47 47
Section 4.3
• Uniform or Localized Loss of
Thickness
• All Industries
• Aqueous Corrosion
48. 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)
51. 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 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 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 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 55
4.3.4: Cooling Water Corrosion
Saltwater vsCarbon Steel and Alloys
0
10
20
30
40
50
60
70
80
90
0 50 100 150 200 250
Temperature F
C
orrosion
R
ate
(m
py)…
CS Adm. Brass 70-30 Cu-Ni T
itanium
56. 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 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 58
4.3.8: Microbiologically Induced
Corrosion (MIC)
• Surface pits under
tubercles; carbon steel
• Pits in cross-section;
Type 316 stainless steel
59. 59 59
Anaerobic Sulfate Reducing Bacteria (ASRB)
Potentially the most common & destructive bacteria group. ASRB reduce
sulfates in the water, soil or oil, to H2S 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 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 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
65. 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 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 67
4.4.2: High-Temp Sulfidation
• Reaction of metals with
hydrogen sulfide
Fe + H2S FeS + H2
FeS + H2S FeS2 + H2
• Sulfur compounds in crude oil
decompose to H2S
• H2S content determines crude
corrosivity
68. 68 68
4.4.2: High-Temp Sulfidation
• Crude units, vacuum units
• >1 ppm H2S with no hydrogen
• Upstream of hydrocrackers and
hydrotreaters
• Extremely sensitive to temperature
• Add Cr to increase sulfidation
resistance
69. 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
75. 75 75
4.5: Stress Corrosion Cracking
(SCC)
Depends on environment, material, and
temperature. Avoidance measures:
ƒ Change metallurgy
ƒ Stress relief; PWHT
ƒ Reduce temperature
ƒ Use coatings
ƒ Reduce stress
ƒ Design changes: avoid wet/dry conditions
76. 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 77
Transgranular, surface initiated cracks
In sensitized stainless steels, cracking can be
intergranular (along grain boundaries)
4.5.1: Chloride SCC
80. 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
82. 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 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 84
Intergranular cracking along grain boundaries
4.5.3: Caustic SCC
Caustic Cracking in Carbon Steel
Caustic Cracking in 316SS Steel
85. 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 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
91. 91 91
5.1.1.1: Amine Corrosion
• Amines are used to remove corrosive
acid gases (H2S & CO2) from process
gases and liquids
• Amines can contain acid gases and
corrosive degradation products
• Contaminants include abrasive solids,
salts, process chemicals
92. 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
94. 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 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 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 97
5.1.1.2: Ammonium Bisulfide
Corrosion
• Aqueous corrosion mechanism where
H2S and NH3 exist simultaneously
(NH3+H2S = NH4HS)
• Hydrotreater and FCC overhead systems
(especially effluent air coolers and inlet/
outlet piping
• Amine regenerator overhead systems
• Sour water stripper overhead systems
98. 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 (NH4HS conc.
> 20-30 wt.%)
99. 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. 100 100
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. 101 101
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. 102 102
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
104. 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. 105 105
5.1.1.5: H2/H2S Corrosion
• Occurs in the presence of hot H2 and
H2S simultaneously
• Corrosion rate depends on temperature
and partial pressure of H2S
• Usually uniform metal loss
• H2 results in porous non-protective iron
sulfide scale
106. 106 106
5.1.1.5: H2/H2S 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)
108. 108 108
5.1.1.5: H2/H2S 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/H2S Corrosion: Cr alone is not
beneficial. Requires upgrade to 304,
316 SS
112. 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. 113 113
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
123. 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
126. 126 126
5.1.2.3: Wet H2S 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. 127 127
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
129. 129 129
5.1.2.3: Wet H2S 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. 130 130
5.1.2.3: Avoiding Wet H2S
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. 131 131
5.1.2.3: Wet H2S 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. 132 132
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. 133 133
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
138. 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. 139 139
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. 140
Questions ?
Please feel free to contact me:
Charlie Buscemi
charlie.buscemi@stress.com
Mobile: (504) 650-2427
Office: (504) 889-8440
