Api 571 Training Course 4z722z

API 571 for Inspectors – “Damage Mechanisms Affecting Fixed Equipment in the Refining Industry”

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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 2

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

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Common Alloys Used in the Petrochemical Industry

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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: hightemperature 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) 5

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Stainless Steels Chromium SS:

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Type 410 (12% Cr), Type 430 (17% Cr) For high-temp sulfidation in non-hydrogen environments (esp. atmospheric Crude Units, vacuum units)

Austenitic SS:

• • • • •

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“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 6

Specialty Alloys – Aqueous Corrosion • Duplex SS (22Cr-5Ni-3Mo) for better SCC and • • • 7

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 7

Alloys for High-Temperature Corrosion & Strength • Incoloy 800, 800H, 825 (35Ni-20Cr): • •

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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) 8

Heat Exchanger Alloys • iralty brass (cooling water exchangers) • Copper-Nickel (90-10 Cu-Ni, 70-30 Cu-Ni): •

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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

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API RP 571 • Section 1 – Intro & Scope (2 pgs.) • Sec. 2 – References (API, ASME, • • • • 10

ASTM, NACE, etc.) (2 pgs.) Sec. 3 – & 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.) 10

Example of a PFD Denoted with Damage Mechanisms

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Section 4.2 • Mechanical and Metallurgical •

Failure Mechanisms All Industries

(Thermal effects, aging, embrittlement, creep & stress rupture, fatigue, erosion) 12

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4.2.2: Spheroidization • Changes in CS and low-alloy • • • 13

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 13

4.2.2: Spheroidization

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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. 15

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4.2.2: Spheroidization •

Inspection techniques: -- Field Metallurgical Replication (FMR, “replicas”) -- Field hardness testing (Brinell) -- remove samples for lab analysis

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4.2.5: 885ºF Embrittlement • Long-term exposure of duplex and • •

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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 17

4.2.5: 885◦F Embrittlement • Not pressure-containing components • These alloys are used only for

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internals in the susceptible temperature range (cladding, trays, etc. in FCC, coker, and Crude towers) May result in difficulty welding or straightening affected components 18

4.2.5: 885◦F Embrittlement

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Inspection techniques: -- Field hardness testing (Brinell) -- Bend test -- Charpy impact testing

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4.2.6: Sigma Phase Embrittlement

• Occurs in 300-series stainless steels • • 20

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 20

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 21

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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

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4.2.6: Schaeffler Diagram

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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 24

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4.2.8: Creep & Stress Rupture

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4.2.8: Creep & Stress Rupture

• Occurs at elevated temperatures (see API 530):

CS: 700°F 5Cr: 800-850°F 9Cr: 800-850°F 300-series SS: 900°F + 26

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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)

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Creep Voids and Fissures at 500X

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4.2.8 – Larson Miller Curves – API 530

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4.2.8: Stages of Creep

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4.2.8: Creep & Stress Rupture • • • • 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 31

4.2.8: Creep & Stress Rupture •

Inspection techniques: -- Visual inspection for bulges ------

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Go/no-go gauging Strapping (diametral expansion) Radiography (RT) Ultrasonic thickness testing (UT) Field replication (FMR)

Monitor with TI’s and infrared (IR) scans 32

4.2.9: Thermal Fatigue

• All metals can undergo thermal • • 33

fatigue Cyclic stress due to alternating temperatures results in crack formation and propagation Typically forms wedge-shaped or carrot-shaped, scale-filled cracks 33

4.2.9: Thermal Fatigue Wedge-Shaped, Oxide-Filled Cracks

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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-toshell welds, skirt welds

• Smooth out weld contours 35

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4.2.9: Thermal Fatigue

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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

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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 37

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4.2.16: Mechanical Fatigue • Characteristic • •

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“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 38

4.2.16: Mechanical Fatigue Crack origin at a major transition in shaft thickness

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4.2.16: Mechanical Fatigue

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4.2.16: Mechanical Fatigue

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4.2.16: Mechanical Fatigue • For some metals, an “endurance limit” • •

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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)

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4.2.16: Mechanical Fatigue • For other metals, no limit exists • •

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(stainless steels, non-ferrous alloys) Fatigue cracking will eventually occur The number of cycles required is a function of the alternating stress 43

Mechanical Fatigue Life 0.80 Length of Crack in.

0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00 (0.10) 0

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Fatigue Life Expended (%)

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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 45

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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) 46

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Section 4.3 • Uniform or Localized Loss of Thickness • All Industries • Aqueous Corrosion

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4.3.1: Galvanic Corrosion • • • •

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Electrical current flowing between dissimilar metals in an electrolyte (wet corrosive environment) Battery cell Preferential, accelerated attack of the more active metal (anode) Dissimilar ts located in water (cooling water heat exchangers) 48

4.3.1: Galvanic Corrosion Electrolyte

SS

CS

Electrolyte

CS 49

Mg 49

Inspection Techniques for: 4.3.1 Galvanic Corrosion 4.3.2 Atmospheric Corrosion -- Visual inspection -- Ultrasonic thickness testing

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4.3.3: Corrosion Under Insulation (CUI) • • • •

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Rapid corrosion of carbon steels and lowalloy 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 s, leaking steam tracing where moisture penetrates the insulation 51

4.3.3: Corrosion Under Insulation (CUI) • • • • • 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 52

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

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4.3.4: Cooling Water Corrosion • Oxygen scavengers, pH control, fluid • • • 54

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 Cu-Ni, duplex SS, titanium, epoxy coated tubes 54

4.3.4: Cooling Water Corrosion Saltwater vs Carbon Steel and Alloys 90 80

Corrosion Rate (mpy)…

70 60 50 40 30 20 10 0 0

50 CS

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100 150 Temperature F . Brass

70-30 Cu-Ni

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250

Titanium

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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 56

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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 57

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4.3.8: Microbiologically Induced Corrosion (MIC) •

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Surface pits under tubercles; carbon steel

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Pits in cross-section; Type 316 stainless steel

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4.3.8: MIC - Types of Bacteria 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 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.

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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 60

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4.3.8: MIC – Inspection • Check for fouling of HX bundles, tank & drum • • • •

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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

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Section 4.4 • High-Temperature Corrosion • Above 400°F • All Industries

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4.4.1: High-Temp Oxidation

• Add chromium to increase oxidation resistance: ƒ CS: 10 mpy rate at 1050°F ƒ 2-1/4Cr: at 1100°F ƒ 5-9 Cr: at 1200°-1250°F ƒ 304SS: at 1550°F ƒ Incoloy 800/H: at 1700°F ƒ HK, HP: > 1900°F 63

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4.4.1: Oxidation Rates

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4.4.1: High-Temp. Oxidation

• Furnace tubes & hangers, burners, •

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refractory anchors Can be non-uniform on tubes due to flame impingement

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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 66

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4.4.2: High-Temp Sulfidation • Reaction of metals with hydrogen sulfide

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Fe + H2S

FeS + H2

FeS + H2S

FeS2 + H2

Sulfur compounds in crude oil decompose to H2S

• H2S content determines crude 67

corrosivity

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4.4.2: High-Temp Sulfidation • Crude units, vacuum units • >1 ppm H2S with no hydrogen • Upstream of hydrocrackers and • • 68

hydrotreaters Extremely sensitive to temperature Add Cr to increase sulfidation resistance 68

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

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4.4.2: Sulfidation: Vacuum Column Bottoms Pump

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4.4.2: Sulfidation: Vacuum Column Bottoms Pump

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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) 72

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4.4.2: Sulfidation – NACE Publication 34103

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Section 4.5 • Environment – Assisted Cracking (SCC) • All Industries

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4.5: Stress Corrosion Cracking (SCC) Depends on environment, material, and temperature. Avoidance measures: ƒ Change metallurgy ƒ ƒ ƒ ƒ ƒ 75

Stress relief; PWHT Reduce temperature Use coatings Reduce stress Design changes: avoid wet/dry conditions 75

4.5.1: Chloride SCC • • • • • • 76

Aqueous mechanism Requires water with >50 ppm ClAbove ~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 76

4.5.1: Chloride SCC Transgranular, surface initiated cracks In sensitized stainless steels, cracking can be intergranular (along grain boundaries)

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Sensitization of 300-Series SS

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4.5.1: Chloride SCC Effect of Temperature and Chloride Concentration

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4.5.1: Chloride SCC • Susceptible: 300-series SS heat • •

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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 80

4.5.1: Chloride Content of Some Materials

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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

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4.5.3: Caustic SCC • • • • • • 83

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 83

4.5.3: Caustic SCC Intergranular cracking along grain boundaries

Caustic Cracking in Carbon Steel Caustic Cracking in 316SS Steel 84

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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 nickel alloys 85

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4.5.3: Caustic SCC • 300-series stainless steels can crack • •

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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 86

4.5.3: Caustic SCC

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4.5.3: Caustic SCC of Carbon Steel – NACE SP 0403

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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 89

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Section 5.1.1.1: • Uniform or Localized Loss of Thickness • Refining Industry

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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 91

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5.1.1.1: Amine Corrosion

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Localized metal loss, especially in high turbulence areas

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Caused by flashing of acid gases (H2S and CO2)

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High acid gas loading and salt levels can lead to hydrogen blistering & HIC

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Can cause SCC in non-post weld heat treated equipment

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Rich amine is more corrosive 92

5.1.1.1: Amine Corrosion

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5.1.1.1: Amine Corrosion •

Design for 6 fps max. velocity on rich side, 20 fps max. on lean side

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Decrease turbulence

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Upgrade piping, valves, tees to 304L, 316L stainless steel

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Clad vessels with 300-series stainless steels

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5.1.1.1: Amine Corrosion Highly susceptible areas:

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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) 95

5.1.1.1: Amine Corrosion

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• • • •

Visual inspection

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Size stress-corrosion cracks with dye penetrant (PT) and wet fluorescent magnetic particle testing (WFMT)

Automatic or grid ultrasonic (UT) radiography (RT) for general metal loss Installation of corrosion coupons and electrical resistance (ER) probes

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5.1.1.2: Ammonium Bisulfide Corrosion

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Aqueous corrosion mechanism where H2S and NH3 exist simultaneously (NH3+H2S = NH4HS)

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Hydrotreater and FCC overhead systems (especially effluent air coolers and inlet/ outlet piping

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Amine regenerator overhead systems Sour water stripper overhead systems 97

5.1.1.2: Ammonium Bisulfide Corrosion • •

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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.%)

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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

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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 100

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5.1.1.4: HCl Corrosion • •

Tops of atmospheric and vacuum towers

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Acid is the result of hydrolysis of magnesium and calcium chloride salts in crude oils

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Desalting can reduce HCl formation

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Atmospheric & vacuum crude distillation unit overhead streams

Corrosion occurs where water condenses Upgrades: Monel trays and cladding 101

5.1.1.4: HCl Corrosion • • •

General wasting & washed out appearance

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Monel has been successful as trays at top of distillation tower and in O/H vapor line

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Severe thinning with no scale Corrosion rate can exceed an inch per year (1000 mpy) on carbon steel at elevated temperatures

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5.1.1.4: HCl Corrosion

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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

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5.1.1.5: H2/H2S Corrosion •

Occurs in the presence of hot H2 and H2S simultaneously

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Corrosion rate depends on temperature and partial pressure of H2S

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Usually uniform metal loss

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H2 results in porous non-protective iron sulfide scale 105

5.1.1.5: H2/H2S Corrosion • CS-9Cr: significant corrosion • • • • 106

> 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) 106

5.1.1.5: H2/H2S Corrosion – Corrosion Rates

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5.1.1.5: H2/H2S Corrosion – • • •

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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 304, 316 SS 108

5.1.1.5: H2/H2S Corrosion –

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5.1.1.5: H2/H2S Corrosion

• Inspection Techniques: -- Visual inspection + -- Ultrasonic thickness (UT) -- Radiography (RT)

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5.1.2.3: SCC Resistant Materials – NACE MR 0103

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5.1.1.11: Sulfuric Acid Corrosion • Sulfuric acid alkylation plants • Can result in washout and severe • • • 112

thinning of carbon steel CS cannot be used for weak acid Refineries use carbon steel extensively for strong acid concentrations (95100%) at near ambient temperatures Can require large corrosion allowances 112

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 113

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5.1.1.11: Sulfuric Acid Corrosion

Corrosion of Carbon Steel 114

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5.1.1.11: Sulfuric Acid Corrosion

Corrosion of Alloy 20 115

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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

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Section 5.1.2 • Environment-Assisted Cracking • Refining Industry

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5.1.2.3: Wet H2S 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 118

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5.1.2.3: Wet H2S Cracking

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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

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Mostly at ambient temperature, up to about 150°F 120

Wet H2S Cracking in Distillation Unit Overhead Systems

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Examples of Hydrogen Blistering

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Hydrogen Induced Cracking and Blistering •

Sulfur poisons the “recombination” reaction

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Ho + H o

•

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H2 gas

Hydrogen atoms are absorbed into the steel and form internal hydrogen blisters and cracks 123

HIC and Blistering

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5.1.2.3: Hydrogen Blistering Blisters on the ID surface of affected carbon steel

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5.1.2.3: Wet H2S Cracking -Special Precautions • • •

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Blistered steel is irreversibly damaged If repairs are to be made to damaged steel, expect the steel to be hydrogensaturated and potentially embrittled Prior to repairs: consider hydrogen “bake out” at > 400°F

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5.1.2.3: Sulfide Stress Cracking • Cracking of hard metals and weld HAZs • Maintain weld hardness below BHN • • • • 127

200 for CS, BHN 215 for low-alloy steels Valve trim, bolting
5.1.2.3: Sulfide Stress Cracking (SSC)

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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 129

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5.1.2.3: Avoiding Wet H2S Cracking in Welds

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PWHT welds to reduce weld hardness and residual stress

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BHN 200 max. for carbon steel; BHN 215 max. for low-alloy steels

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PWHT carbon steel at 1100°-1200°F (1 hr./inch, 1 hr. min.)

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PWHT 1-1/4Cr & 2-1/4Cr steel at 1300°-1375°F 130

5.1.2.3: Wet H2S Cracking •

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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) 131

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 • • • • 132

(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) 132

5.1.3.1: High Temperature Hydrogen Attack •

Hydrogen in 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

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5.1.3.1: High-Temperature Hydrogen Attack

Hydrogen Attack “Formation of Microfissures”

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5.1.3.1: High-Temperature Hydrogen Attack in Carbon Steel

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5.1.3.1: High-Temperature Hydrogen Attack – API 941

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5.1.2.1: API 941 Limits for HTHA

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5.1.3.1: HTHA Prevention •

Cr & Mo additions improve resistance to HTHA

•

New equipment should be fabricated from HTHAresistant materials for the design operating pressures and temperatures (according to API 941 guidelines)

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Existing equipment that does not meet API 941 guidelines should be removed from service or subject to concentrated frequent inspection

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HTHA causes a loss in strength and fracture toughness and can result in brittle fracture. Equipment containing HTHA may not be fit for service

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5.1.3.1: HTHA Inspection • • • • • • 139

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 139

Questions ? Please feel free to me:

Charlie Buscemi [email protected] Mobile: (504) 650-2427 Office: (504) 889-8440 140