api 571 training course

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


•

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


•

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)

•


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


•

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


•

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•


--

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

•


--

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


•

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


41


41

42 42


•

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


•

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


•


--

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


•

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


•

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

•


--

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


•

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


•

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


•

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


•

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

•


--

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


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


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

•


--

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


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


•

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


•

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


Mitigation:•

Reduce velocity and turbulence

•

Clad severe areas w/ 300-series SS•

Use Incoloy

825 for effluent air cooler

headers & piping

100 100


•


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•


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


•

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


Corrosion of Carbon Steel

115 115


Corrosion of Alloy 20

116 116


•


--

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

[email protected]

Mobile: (504) 650-2427

Office: (504) 889-8440

mailto:[email protected]

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