Corrosion Mechanisms - Material Selection and Corrosion Control (Technip Italy)

CORROSION MECHANISMS MATERIAL SELECTION AND CORROSION CONTROL IN REFINERY

Flavio Cifà Michele Scotto di Carlo

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“Corrosion

is defined as the destruction or deterioration of a material because of reaction with its environment” Mars G. Fontana

CONTENTS

n CORROSION AND DEGRADATION MECHANISMS èCORROSION PROCESSES KINETIC èLOW TEMPERATURE DEGRADATION MECHANISMS l GENERAL CORROSION – CO2 corrosion – Wet hydrogen sulfide corrosion l GALVANIC CORROSION l PITTING CORROSION l CREVICE CORROSION l UNDER DEPOSIT CORROSION l STRESS CORROSION CRACKING – Chloride stress corrosion cracking (CSCC) – Sulfide stress cracking (SSC) – Alkaline stress corrosion cracking (ASCC) – Caustic cracking – Amine cracking – Cracking in H2O-CO-CO 2 systems

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CONTENTS è LOW TEMPERATURE CORROSION MECHANISMS (CONTINUE) l SENSITIZATION AND WELD DECAY CORROSION (INTEGRANULAR) – Sensitization – Weld Decay – knife line attack – Polythionic Acid Stress corrosion Cracking (PASSC) l EROSION CORROSION l MICROBIOLOGICALLY INDUCED CORROSION l CORROSION UNDER INSULATION l HYDROGEN DAMAGE

è HIGH TEMPERATURE CORROSION MECHANISMS l l l l

NAPHTENIC ACID CORROSION HIGH TEMPERATURE OXIDATION SULFIDATION HIGH TEMPERATURE HYDROGEN DAMAGE

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CONTENTS

n MATERIALS AND CORROSION PROTECTION è MATERIAL SELECTION GUIDELINE è CARBON STEEL è LOW ALLOYED STEELS è STAINLESS STEELS è COPPER ALLOYS è NICKEL ALLOYS è TITANIUM ALLOYS è POLIMERIC MATERIALS è CATHODIC PROTECTION

n MATERIAL SELECTION AND CORROSION CONTROL IN REFINERY UNITS è DESALTER è ATMOSPHERIC DISTILLATION UNIT è VACUUM DISTILLATION UNIT è AMINE UNIT è HYDRODESULPHURIZATION UNIT è SOUR WATER STRIPPER UNIT

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CORROSION AND DEGRADATION MECHANISMS General criteria

CORROSION KINETICS

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n STATIONARY KINETICS Steady corrosion rate which often allows: è corrosion rate prediction trough laboratory tests, bibliographic data and estimation models. è Monitoring on stream and off stream è Upset conditions are not decisive on corrosion process R corr

n INCUBATION PERIOD KINETICS It presents an incubation period which closes with high corrosion rate (cracking). Stationary

è “upset conditions” are decisive. Incubation period è The incubation period may be very short (h!!!) ti Time è The corrosion process once started (t > ti) continues up to the rupture independently from the incubation conditions persistence. • Whenever “upset conditions” are decisive for the described corrosion mechanism they will be clearly highlighted with

UPSET

LOW/HIGH TEMPERATURE CORROSION

LOW TEMPERATURE CORROSION n Temperature < 260°C n Aqueous phase and presence of ionic species HIGH TEMPERATURE CORROSION n Temperature > 260°C n Aqueous phase not necessary

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CORROSION AND DEGRADATION MECHANISMS Low temperature corrosion mechanisms

LOW TEMPERATURE DEGRADATION MECHANISMS n n n n n n n n n n n

GENERAL CORROSION GALVANIC CORROSION PITTING CORROSION CREVICE CORROSION UNDER DEPOSIT CORROSION STRESS CORROSION CRACKING SENSITIZATION AND WELD DECAY CORROSION (INTEGRANULAR CORROSION) EROSION CORROSION MICROBIOLOGICALLY INDUCED CORROSION CORROSION UNDER INSULATION HYDROGEN DAMAGE

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GENERALIZED CORROSION AT LOW TEMPERATURE n ANODE “location where metal dissolution takes place (i.e. Fe→ →Fe2+ )” n CATHODE: “location where O2, H+ or metal reduction takes place (i.e. Fe3+→ Fe2+)” n No specific location for anode and cathode n Anode and cathode move with time n Can be monitored, measured and predicted

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GENERALIZED CORROSION AT LOW TEMPERATURE

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Can be uniform or not CONTROL: n Select proper metallurgy n Corrosion allowance (function of corrosion rate and required lifetime) n Inhibitor n Cathodic Protection n Monitoring Some metal-environment combinations known to results in general corrosion: Corrosion rate of various alloys in CS - dilute mineral acid CS - CO2 and/or H2S in aqueous phase boiling mixtures of 50% acetic acid and varying proportions of formic acid. CS - seawater Test time 1+3+3 days. (by SANDVIK) SS - organic acid at high T (i.e. 100- 200 °C) Ti - concentrated sulfuric acid

GENERALIZED CORROSION AT LOW TEMPERATURE- CO2

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An example of generalized corrosion at low temperature is CO2 corrosion on carbon steel. Requires a presence of aqueous phase and it’s due to the low pH. It can be tentatively predicted using a software It’s a function of: n PCO2 n Temperature n System Fluid dynamics (influences scale stability ) n Presence of H2S and/or organic acid n O2 content CONTROL: it can be controlled with CS + CA up to corrosion rate (CR) 0.6mm/y. For higher CR upgrade metallurgy to 304 (316 not necessary)

GENERALIZED CORROSION AT LOW TEMPERATURE - H2S Another example of generalized corrosion at low temperature on carbon steel is Wet Hydrogen Sulphide corrosion. (Note: includes also risk of SSC and hydrogen damage). It requires a presence of aqueous phase and it’s due to the low pH and to the reaction between S and Fe (formation of FeS scale) The stability of FeS scale is influenced by pH and presence of contaminants (i.e. CN-) The temperature rise increase CR CR is hardly predictable

NOTE: CR is influenced also by pH, fine metal composition, presence of contaminants (i.e. CN), etc... (by NACE)

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GENERALIZED CORROSION AT LOW TEMPERATURE - H2S H (atomic) can diffuse into the metal causing: n cracking n blistering n embrittlement (see also SSC and Hydrogen damage)

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Graph by UOP

CONTROL: Wet H2S general corrosion can be controlled with CS + CA up to corrosion rate (CR) 0.6mm/y. For higher CR upgrade metallurgy to SS The phenomenology related to hydrogen attack are taken into account requiring HIC resistant specs (composition + test NACE TM 0284). Note: consider as valid alternative SS cladding instead of CS HIC resistant

GENERALIZED CORROSION AT LOW TEMPERATURE

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GALVANIC CORROSION n Preferential corrosion of one metal of two or more electrically connected dissimilar n It requires an aqueous environment which is corrosive to at least one metal and with a non negligible conductivity n It’s related to the ∆V between the metals in the considered environment (i.e. see galvanic series in seawater).

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GALVANIC CORROSION ALL the following parameter have to be verified to evaluate risk of galvanic corrosion n Verify the allowable ∆V: è if it is not significant (i.e. the coupled metals are close in the galvanic series measured in the considered environment) don’t worry about CG n Verify the medium corrosivity: è if the fluid is not aggressive towards at least one of two coupled metals (i.e CS - SS in neutral deoxygenated water) CG is not a problem n Verify the fluid conductivity: è if it is very low (i.e. demi water of hydrocarbons) CG are not an issue n Verify cathodic/anodic areas: è if the cathodic area is << of anodic area (don’t forget to consider lining!!) galvanic corrosion can be tolerated (i.e. SS bolting on CS flange)

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GALVANIC CORROSION

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CONTROL: n Ratio cathodic/anodic areas (if the ratio increase the CR↑ ↑). n Control environment (i.e. pH↑ ↑, remove O2... ) n Use of coating (either on both surfaces or on cathodic surface, NEVER only on anodic surface) n Use insulation kit to break electrical continuity n Cathodic Protection Metal coupling that can generate GC (the first is attached): CS-SS CS-Copper alloy CS-Ti CS-Hastelloy SS-Ti SS - Hastelloy Insulation kit

GALVANIC CORROSION

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GALVANIC CORROSION

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GALVANIC CORROSION

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PITTING CORROSION n PITTING: form of extremely localized attack that results in hole in the metal. One of the most dangerous and insidious form of corrosion. n It causes equipment to fail because of perforation with only a small weight loss n Normally occurs in active/passive metals (i.e. SS series 300) in passive state n Requires depassivating species (i.e. chloride or other halides ) n Worse problem at low velocity and high T n Hard to detect and/or predict UPSET

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PITTING CORROSION CONTROL: n avoid metal/environment combination susceptible to pitting n check environmental conditions especially è [Cl-] o [X-] è Temperature è O2 è Minimum fluid velocity A parameter to evaluate pitting resistance of SS is PREN (pitting resistance equivalents number): PREN = Cr + 3.3 Mo + 16N

Critical pitting temperatures (CPT) for SAF 2205, AISI 304 and AISI 316 at varying concentrations of sodium chloride (potentiostatic determination at +300 mV SCE), pH»6.0 (by SANDVIK)

UPSET

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PITTING CORROSION

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Examples of metals susceptible to pitting in chlorides environment: n SS (Ferritic, Austenitic, Duplex) n Fe-Ni-Cr Alloy (Incoloy) n Aluminum Alloy UPSET

n Copper Alloy Immune Ti Alloy C Alloy 625

Very resistant 90/10 Cu/Ni Admiralty brass

Resistant 70/30 Cu/Ni Tin Al bronze

Acceptable Monel 316 (+ CP) Alloy 825 Alloy 20

Pitting resistance in seawater

Not Acceptable SS series 400 304 Nickel

PITTING CORROSION

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PITTING CORROSION

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CREVICE CORROSION Selective corrosion in crevice n CC requires a stagnant zone where it’s possible to develop different conditions from bulk (inhibitor, oxygen, pH, Cl-) n CC requires an aggressive environment (i.e. presence of chloride) n If temperature likelihood ↑

↑

crevice

UPSET

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CREVICE CORROSION CONTROL: n Use materials less sensitive to pitting (the corrosion mechanisms are similar therefore a material resistant to pitting corrosion is also resistant to crevice corrosion. See slide 99) n avoid stagnant zone n don’t use threaded connections n control O2 content Some materials susceptible to CC: è SS è Ni alloy UPSET è Ti Preferentially locations for CC: n Flanged connection n Tube/Tubesheet connection n Threaded connections n Plate Heat Exchangers

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CREVICE CORROSION

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CREVICE CORROSION

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UNDER DEPOSIT CORROSION Corrosion enhanced by the presence of scales (can be aggressive i.e NH4Cl or not) Under deposit corrosion results from difference between local and bulk environment (i.e oxygen, pH, presence of aggressive ions Cl. See also crevice and pitting corrosion) If chloride are present H+ “drawn” under deposits (pH drops below 4 increasing corrosion rates) Most common materials are subjected to UDC including CS, austenitic SS, nickel alloy (Inconel 625, Hastelloy and Ti are very resistant)

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UNDER DEPOSIT CORROSION

Refinery examples: any location in which scaling and/or fouling occur especially if chloride or oxygen are present CONTROL TECHNIQUES n treat the source of the problem (i.e. corrosion or fouling) n design equipment to minimize deposition. Metallurgy may solve corrosion problem but not performance loss n antifoulant may be helpful

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UNDER DEPOSIT CORROSION AMMONIUM BISULFIDE n frost from gas to solid at a temperature depending on NH3 H2S concentration n Is corrosive vs CS but not vs SS or higher alloy n Causes very rapid fouling Refinery examples n REACs (hydrotreaters/hydrocrackers) n Crude unit overhead n FCC (overhead in separator section) CONTROL n wash water è use continuous washing (20%min water not vaporized) è inject upstream of ammonium bisulfide dew point n Use balanced piping for REACs n Upgrade metallurgy

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UNDER DEPOSIT CORROSION AMMONIUM CHLORIDE n frost from gas to solid at a temperature depending on NH3 HCl concentration n Is corrosive vs CS and SS. Ti and Inconel 625 may offer sufficient protection n Causes very rapid fouling REFINERY EXAMPLES n Crude unit overhead n hydrotreaters (REACs, overhead in separator section) n Catalytic reformer (REAC, separator, stabilizer, recycle gas compressor) n FCC (overhead in separator section) CONTROL n wash water è use continuous washing (20%min water not vaporized) è inject upstream of ammonium chloride dew point n Use balanced piping for REACs n Upgrade metallurgy (expensive solution)

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STRESS CORROSION CRACKING

Cracking corrosive process that requires the simultaneous presence of:

n Material in passive state susceptible to attack nAggressive environment nstress state èresidual (i.e. welds) èapplied (i.e. bends)

UPSET

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Table from ASM Vol 13 Corrosion

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Main type of SCC n Chloride stress corrosion cracking (CSCC) n Sulphide stress cracking (SSC) n Alkaline stress corrosion cracking (ASCC) n Polythionic Acid Stress Corrosion Cracking (PASSC) n Cracking in H2O-CO-CO2 system

UPSET

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CHLORIDE STRESS CORROSION CRACKING

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Material susceptible to CSCC n austenitic SS, duplex , ferritic (sensibilized) n Fe-Cr-Ni alloy (Incoloy) n Copper alloy n Bronze/Brasses n Aluminum n Cobalt alloy (i.e. Stellite)

UPSET

View of chloride stress corrosion cracking in a 316 stainless steel chemical processing piping system. Chloride stress corrosion cracking in austenitic stainless steel is characterized by the multibranched "lightning bolt" transgranular crack pattern. (Mag: 300X)

CHLORIDE STRESS CORROSION CRACKING

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For SCC Ni content is fundamental SS serie 300

CONTROL: n limit O2 content n limit stress (∃ ∃ threshold value) n Control temperature n Control pH N.B. H2S lowers CSCC limits UPSET

SCC resistance in oxygen-bearing (abt. 8 ppm) neutral chloride solutions. Testing time 1000 hours. Applied stress equal to proof strength at testing temperature. (by SANDVIK)

SULPHIDE STRESS CRACKING

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SSC is defined as cracking of a metal under the combined action of tensile stress and corrosion in the presence of water and H2S SSC is a form of hydrogen stress cracking resulting from absorption of atomic hydrogen that is produced by the sulfide corrosion reaction on the metal surface SSC is influenced by: n Chemical composition (P,S,Mn), hardness, metal thermal treatment nTotal tensile stress (applied plus residual) n Hydrogen flux (function of [H2S], pH, CN-, etc..) n Time (Note: short term conditions i.e. shutdowns can be sufficient) n Temperature (increase H 2S dissociation and H diffusion)

H2S SSC Cracks in a 17-4 pH stainless steel

UPSET

SULPHIDE STRESS CRACKING

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Some environmental conditions known to cause SSC are those containing free water (in liquid phase) and: n >50 ppmw dissolved H2S in the free water or n free water pH<4 and some dissolved H2S present or n free water pH>7,6 and 20ppmw dissolved HCN in the water and some dissolved H 2S present n >0.0003 MPa absolute partial pressure H2S in the gas in processes with a gas phase CONTROL: For Refinery apply NACE MR0103 For upstream (oil and gas production) apply NACE MR0175 Note: Pay attention to thermodynamic model used in the simulators and to hypothesis to calculate % H2S in free water UPSET

ALKALINE CRACKING

cracking in caustic environment carbonate cracking cracking in amine environment Main materials involved: n Carbon steel n Low alloy steel n Stainless steel n Copper alloy

UPSET

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CAUSTIC CRACKING Cracking due to exposition of CS to hot caustic solution (i.e. NaOH, KOH) CONTROL: use the materials indicated on Caustic Soda Service Graph (see also SR) by NACE Note: If for the service austenitic SS has been specified, check chloride concentration and T max. UPSET Caustic Soda Service Graph by NACE

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AMINE CRACKING

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Cracking caused by amine (mainly due to dissolved CO2 e H2S). Amine cracking happens preferentially in the heat affected zone (HAZ). Lean amine is not corrosive vs CS and it shows less probability to cause cracking. MEA is more aggressive than DEA o MDEA If temperature ↑ cracking likelihood ↑ (consider also short term condition, i.e. Steam out) CONTROL: è SR (included PWHT) in accordance with API 945 (595 °C < T < 649°C, min holding time 1h) è hardness < 200HRB SR is suggested, function of used amine, at the following operating T: nMEA : all operating T nDEA: T > 60°C nMDEA : T> 82°C UPSET

CRACKING IN CO-CO2-H2O SYSTEMS

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It can happen in pressure system with the simultaneous presence of CO-CO2-H2O n low T (maximum risk in the range 20-60°C) n minimum CO and CO2 pressure required CONTROL:

Check environmental conditions (T, water, PCO & PCO2) Use SS (12 Cr o 304; 316 not necessary) Range of SCC susceptibility

CO partial pressure (kPa)

1400 1200 1000 800 600 400 200 0 0

200

400

600

800

1000

1200

CO2 partial pressure (kPa) Published data

SASOL

Mossgas

1400

1600

1800

SENSITIZATION ISSUES (INTERGRANULAR CORROSION) Main degradation forms related: n Sensitization n Weld decay n Knife line attack n Polythionic acid stress corrosion cracking MECHANISM: 1) A high temperature exposure allows the reaction between Cr and C. 2) Cr carbides precipitates at grain boundaries. 3) Cr depletion in areas surrounding to grain boundaries. (when Cr below 12% the steel is no more SS and corrode like CS).

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SENSITIZATION AND WELD DECAY Sensitization n is not a corrosion mechanism but the Cr depletion may generate intergranular attack. n May occur rapidly due to: weld, heat treatment and operating temperature. n The sensitization range (temperature and time) is related to the material. Weld decay n The Cr depletion is related to the heating in areas surrounding the weld. n Varies with welding conditions n varies with distance form the weld Knife line attack n Same mechanism of weld decay n on chemically stabilized material

Heat affected zone (HAZ)

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SENSITIZATION CONTROL TECHNIQUES Sensitization control n Materials selection: è normal and high carbon grades: Carbon content 0,03 % - 0,10 l Ferrous (i.e. 304/316) and Ni-Cr alloys Subjected to sensitization. è low carbon grades: below 0,03 % l i.e. 304L, 316 L, Hastelloy C-276 Do not sensitize under welding conditions but are subjected to sensitization under operating conditions è Chemically stabilized material (Nb or Ti) l I.e. 321, 347, Incoloy 801, 825, alloy G, Inconel 625 Ni and Ti form carbides avoiding Cr depletion. Thermal treatment (stabilization) avoids sensitization over long term exposure. l Stabilization heat treatment should be recommended n Procedure mistakes è Cleaning with oily rag before welding introduces C è PWHT in the sensitizing time-temperature range

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INTERGRANULAR CORROSION

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POLYTHIONIC ACID STRESS CORROSION CRACKING (PASCC)

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Intergranular corrosion and cracking caused by the simultaneous presence of: n Sulfide scale n Sensitized material n Oxygen n Stress (residual or applied) n Water n Polythionic Acids (H2SxOy) form (usually during shut down) for reaction of sulfide scale with H2O e O2 Main material subjected to sensitization: n Austenitic or Ni alloy (also low carbon or stabilized) operating at high T (i.e. 370 °C < T < 815°C for 304/316) n Austenitic or Ni alloy (not stabilized) welded

Polythionic acid stress corrosion cracking of type 310 stainless steel. The item was exposed to sulfur containing natural gas in a continuous flare

UPSET

POLYTHIONIC ACID STRESS CORROSION CRACKING (PASCC) Refinery examples: n hydrodesulfurizers n hydrocrackers n hydrogen reformers n FCC n Fired heaters (both external and internal)

UPSET

CONTROL: follow guideline NACE RP0170 n Exclusion of oxygen (air) and water by using a dry nitrogen purge n Alkaline washing with soda ash. Avoid washing of zone that can’t be drained n Exclusion of water by using a dry purge with a dew point lower than -15°C

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CORROSION UNDER INSULATION

For further information on CUI see NACE RP 0198

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HYDROGEN DAMAGE

Atomic hydrogen even produced by low temperature corrosion phenomena may diffuse through metal surface causing hydrogen damage. Hydrogen damage is recognized under various forms: n Blistering n Hydrogen Induced Cracking (HIC) n Stress Oriented Hydrogen Induced Cracking (SOHIC) n Hydrogen Embrittlement n High Temperature Hydrogen Attack UPSET

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BLISTERING-HIC-SOHIC Main steps of blistering and HIC n Atomic hydrogen diffuses inside the metal bulk n Inside the metal atomic hydrogen meets the voids (rolling defects) and inclusions (MnS) and re-combines in molecular hydrogen (H2) n Gradually, molecular hydrogen collected in voids and inclusions increases the pressure reaching up to 10 GPa. n The elevated pressure evidenced by surface blistering may lead to local (stepwise) and complete rupture of the plate. n SOHIC is related to residual stresses presents in the metal. UPSET

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BLISTERING-HIC-SOHIC

Influencing and control parameters:

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UPSET

n Chemical composition of the process fluids (presence H2O, pH, H2S, CN, As, Sb) n Voids and inclusions presence n Metal chemical composition and thermal treatments. n Residual stresses (only for SOHIC) n Construction and welding and test procedure according standards. (NACE MR 0175, NACE 0103, NACE TM0284, API 945)

BLISTERING-HIC-SOHIC

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HYDROGEN EMBRITTLEMENT Embrittlement caused by the hydrogen diffusion through the metals. Possible Hydrogen sources: n General corrosion n Galvanic corrosion n Overprotection of cathodic protection. Influencing factors: n Enhanced by CN, As, Sb presence. n May occur on CS, alloyed steels, nickel alloys, Titanium (T > 71° C) Copper alloys are considered immune UPSET

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HYDROGEN DAMAGE

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Critical areas: è “Rich” section of amine units. è Sour water stripper. UPSET è Hydrodesolfurization units. è FCC units. Hydrogen damage control: n Appropriate material selection è Reduction the allowable metal inclusions (S, Mn and P content). è Ca and rare earth addition (shape control of residual inclusions). è Steel HIC resistance according NACE TM0284. n Optimization of process conditions (i.e. H2O, pH) n Construction and welding according standard (i.e. NACE MR0175 NACE 0103). n Correct cathodic protection design and operation. n Use of insulation kit for different metals in electrical contact.

EROSION-CORROSION ♦ Degradation mechanism accelerated by flow conditions of a corrosive fluid in contact with metal surface ♦ Mechanism: Corrosive fluid reacting with metal creates a film scale Fluid removes mechanically the scale exposing uncorroded metal

Material CS Ad. Brass 70-30 Cu Ni (0.05% Fe) 70-30 Cu Ni (0.5% Fe)

Typical corrosion rates in seawater mdd 1ft/sec 4 ft/sec 27 ft/sec 34 72 254 2 20 170 2 199 <1 <1 39

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EROSION-CORROSION Factors influencing erosioncorrosion: n Velocity and fluid turbulence n Temperature n Multiphase flow n Suspended solid n Galvanic effect (i.e.: CS-SS and CS-CuNi in seawater) CONTROL: n Material Selection or lining (i.e. Cu-Ni 66-30-2-2 instead of CuNi 70/30). n Check allowable velocity n Localized preventive measures (i.e. ferrule on tubes inlet). n Change environment (i.e. inhibitor, filtering, temperature).

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EROSION-CORROSION

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MICROBIOLOGICAL INDUCED CORROSION (MIC) MIC refers to corrosion influenced by the presence and activities of microorganisms and/or their metabolites Microorganism (i.e. fungi, bacteria or algae) can be aerobic or anaerobic Generally MIC shows jeopardized attack on CS, localized on SS (i.e. pitting) Microorganism’s growth is influenced by pH, temperature and “food” availability (peak between 30 e 40 °C) Stagnant zone increase attack severity

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MICROBIOLOGICAL INDUCED CORROSION (MIC) Refinery examples: n Cooling water systems n Water layer in tanks n Following hydrotesting

CONTROL: n Use Biocide addition n High thick Coating (i.e. coal tar) n Cathodic Protection (+950 mV) n High quality hydrotest water n Avoid wet dead legs

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CORROSION AND DEGRADATION MECHANISMS High temperature corrosion mechanisms

HIGH TEMPERATURE CORROSION MECHANISMS

n NAPHTENIC ACID CORROSION n HIGH TEMPERATURE OXIDATION n SULFIDATION n HIGH TEMPERATURE HYDROGEN DAMAGE

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NAPHTENIC ACID CORROSION Generalized corrosion at high T (230400 °C) caused by naphtenic acids for crude with TAN > 0.5 (ASTM D 974 T.A.N. as mg KOH/g) or TAN > 0.35 for some licensor. ∃ several type of naphtenic acids Naphtenic acids are very aggressive especially close to their boiling points (thus can attack selectively some locations of the unit ) n Metallurgy: CS and Cr alloy (i.e. 5 - 9 - 12Cr o 304/316 std) are readily attacked n Sulfur content: especially at low fluid velocity, sulfur can mitigate corrosive attack n Velocity: high velocity (>2.7 m/s) increases corrosion rate

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NAPHTENIC ACID CORROSION Refinery examples: n Heaters and Transfer Line in CDU n Diesel section of CDU column (pump-around) n Atmospheric column residue n Vacuum column residue n Gas oil section of VDU CONTROL: n N.B. Check TAN for each cut with operating temperature in the range 260 - 400°C n Stainless steel 317 o 316 with Mo 2.5%min n Monitoring + inhibitor (only for short run) n Use blending to reduce TAN n Neutralization with NaOH (pay attention on caustic embrittlement)

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HIGH TEMPERATURE OXIDATION Generalized corrosion caused by direct oxidation of base material (liquid water not required) Oxidation issues n O2 Concentration n Alloy composition n Metal temperature The source of O2 can be also steam or CO2 The scale composition influences CR Microstructure of iron oxides formed on iron by high-temperature oxidation in air

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HIGH TEMPERATURE OXIDATION

Refinery examples: n Heaters n Boilers CONTROL: n Improve metallurgy (with alloy containing Cr, Ni, Si, Al)

Control environmental conditions, especially: n Sulfur (Increase corrosion rate) n metals (i.e. V which causes V2O5 formation) in fuel n Temperature (if scale ↑ thermal exchange↓ ↓ and lifetime↓ ↓)

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SULPHIDATION

Reaction between Sulfur and metal or alloy at high temperature. Can cause generalized corrosion @ T>260 °C CR is influenced mainly by T and %S (or H2S) Refinery examples: n Topping and Vacuum (@ T >260°C) n HDS (hot heat exchangers, heaters and reactor) n Sulphur Recovery Unit %Cr is fundamental to resist to sulfidation attack. Generally low chrome alloy are used with %Cr higher and higher (1.25-2.25-5-7-9 Cr) up to stainless steel (as 12Cr like 405 and 410) or austenitic (304 or 316)

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SULPHIDATION CONTROL: Use appropriate metallurgy considering CR calculated by available curves (function of metal T, alloy composition and %S for Mc Conomy or H2S for Couper Gorman) n Mc Conomy (API) based on total sulfur content:

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SULPHIDATION

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CONTROL: Use Couper Gorman for fluid containing high H2 and H2S concentration (see also Nelson curves on API 941 for HTHA) Available for several material (i.e. CS, low Cr alloy and SS)

Couper Gorman Curves for carbon steel and 18-8 stainless steel

HIGH TEMPERATURE HYDROGEN ATTACK (HTHA)

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High temperature hydrogen can attack steels in two ways : n Surface decarburization (slight, localized reduction in strength and hardness and an increase in ductility) n Internal decarburization and fissuring (CH4 formation and high localized stresses which lead to the formation of fissures, cracks or blister in the steel) Factors influencing HTHA: n Temperature n H2 pressure n Stress (i.e. welds) n Time (∃ ∃ incubation period)

Hydrogen attack corrosion and cracking on the ID of an 1800 psig carbon steel boiler tube.


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CONTROL: Use Cr-Mo alloy instead of CS (reduces the amount of available carbide) SS are practically immune from HTHA For CS and Cr-Mo alloy refer to API 941 Note: èC-0.5Mo, usually, is not allowed in H2 service èCladding should not be considered as material resistant to HTHA (therefore also base material have to be resistant)

Solids deposition and hydrogen attack corrosion at the ID weld in an 1800 psig carbon steel boiler tube. The arrow marks the direction of flow. (~1X)


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Nelson curves (API 941)

N.B. Add safety margin, below the relevant curve,when selecting steels (11 °C min)

STATISTIC RELEVANCE OF CORROSION FAILURES nCorrosion causes the 55% of the failures in chemical plants (the remaining 45% of the failures are related to mechanical reasons). n General corrosion and SCC show the higher occurrence in corrosion failures (in sum they account 51%).

Types of corrosion failures (duPont) others corrosion 6% General 27%

Stress Corr. Cracking 24%

High temperature corrosion 2% Erosion-corrosion 7%

Crevice 2%

n Crevice corrosion causes only 2% of the failures while Weld corrosion 5% pitting the 14%. nThe sum of Intergranular and weld corrosion is relevant (15%).

Pitting 14%

Corrosion fatigue 3% Intergranular 10%

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“Il campo della corrosione è con molta aderenza paragonabile a quello della medicina. Per I materiali, la corrosione è indubbiamente la più insidiosa delle cause di decadimento e di morte e al corrosionista si presenta il compito in genere assai arduo, di diagnosticare il male, di stabilirne le cause, di prevenirlo ove possibile altrimenti di reprimerlo o contenerlo in limiti accettabili… [A questo scopo il corrosionista deve]… pazientemente costruirsi il suo atlante di anatomia patologica dei materiali esposti ai più svariati ambianti aggressivi, edificare il corpus della sua diagnostica, sviluppare una sempre più efficace farmacologia anticorrosionistica.” Roberto Piontelli, 1961

MATERIAL SELECTION AND CORROSION CONTROL Selection criteria, material properties and cathodic protection

MATERIALS AND CORROSION PROTECTION

n n n n n n n n n

CONDITION ASSESMENT AND MATERIAL SELECTION CARBON STEEL LOW ALLOYED STEELS STAINLESS STEELS COPPER ALLOYS NICKEL ALLOYS TITANIUM ALLOYS POLIMERIC MAERIALS CATHODIC PROTECTION

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MATERIAL SELECTION

Phase sequence

Scope of corrosion activities

1. Process development

Conditions assessment

2. Material selection

Ensure the required service life time

Costs decrease 3. Process and material optimization Improve the reliability of the unit 4. Engineering, Procurement, Construction

Ver. corrosion protection measures i.e. CP Control galvanic corrosion Control erosion corrosion On Stream Inspection

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1. CONDITIONS ASSESSMENT Environment type (water/oil content)

TDS & TSS

Contaminants and corrodents Cl , H2S, CN-, NH 3 … Temperature (local)

Oxidizers O2, Cl2, Fe3+, Cu2+… Fire hazard

Marine environment

Pressure

Chemical composition Physical

External conditions Underground

Fluid dynamic

Conditions

Thermal insulation Chemical composition

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Condensation and dew point (local)

Atmospheric env.

Upset conditions

Thermodynamic Physical

Solid Precipitation

Thermodynamic Phase settling Time extension

Probability

2. MATERIAL SELECTION

Conditions

90

Life Time

experience in similar units Density

Heat treating

Strength

Experience and literature Material sel. in similar service within the prj

Corrosion allowance

Costs

Metallurgy

Corrosion protection Galvanic couplings

Material

Joining techniques

Availability

Fabricability

Procurement time

Pre-fabrication Construction

dimensions

Spare parts

Fittings

3. PROCESS AND MATERIAL OPTIMIZATION ØExam of the whole unit Conditions assessment

Material selection Process Engineer

Corrosion Engineer

Process development

ØScope Decrease the project costs Avoid over and under specification Improve the reliability of the unit

91

CARBON STEEL n The material Chemical composition based on Fe and C, can be adjusted to improve the resistance to specific degradation mechanism (i.e. HIC) n Typical conditions: By far the most common material used up to 400°C in refineries due primarily to a combination of strength, availability, low cost, and resistance to fire. n Main contaminants and corrodents: Halides (chlorides), sulfides, ammines, dry ammonia, carbonates, CO2+H2O+CO, cyanides, Hydroxides, nitrates, CO2+H2O, acids, oxygenated demi water. n The degradation mechanisms to be verified: General corrosion, stress corrosion cracking, crevice, under deposit, under insulation, galvanic attack, hydrogen damage, erosion corrosion, high temperature damage (almost all).

92

CARBON STEEL Specific corrosion protection measures. n Design according to soda chart, Mc Conomy, Couper Gorman, Nelson where applicable. n Selection of inhibitors (i.e. acidic water, cooling water, boiling water). n Cathodic protection to control general, galvanic, MIC and crevice corrosion. n Anodic protection to control general corrosion. n Polymeric lining (epoxy, PTFE, GRP, rubber) to control corrosion at low temperature. n PWHT to control SCC. n Electrical insulation from others metals to control galvanic corrosion. n Water injection to control under deposit corrosion.

93

LOW ALLOYED STEEL The materials: n Typical conditions: For high temperature service, or hydrogen and sulfidant atmosphere.

Chemical Composition

94

Max Temperature °C

0,5% Mo

500

1% Cr 0,5% Mo

600

1,25% Cr 0,5% Mo

600

2,25% Cr

1% Mo

625

5% Cr 0,5% Mo

650

9% Cr

650

1% Mo

n Present the same contaminants and corrodents of Carbon steel. n The degradation mechanisms to be verified: As per CS. Specifically Hydrogen high temperature damage and high temperature sulfidation. n Corrosion prevention measures: Design according Nelson diagram, Couper Gorman and Mc Conomy to realize correct selection and evaluation of corrosion allowance.

STAINLESS STEEL

95

n The materials: Designation

Type

Metallurgy

12-13 Cr

405, 410, 410 S

Martensitic, Ferritic

18 Cr 8 Ni

304, 304L, 321, 347

Austenitic

18 Cr 10 Ni Mo

316, 316 Ti

Austenitic

22 Cr 5 Ni Mo N

S31803 (2205)

Duplex

25 Cr 7 Ni Mo N

S32750 (2507)

Super Duplex

20 Cr 18 Ni 6 Mo Cu N

S31254 (254 SMo)

Super Austenitic

20 Cr 24 Ni 6,5 Mo

(Al-6X)

Nickel alloy

n Typical conditions: Acidic and saline water, high temperature and low temperature, waste water, demi water, organic acids. n Main contaminants and corrodents: Halides (chlorides), hydroxides (wet and dry), sulfurous acid (on austenitic), organic acids, Hydrogen sulfide and (by external side) Vanadium, molten zinc and molten aluminum.

STAINLESS STEEL n The degradation mechanisms to be verified: General corrosion, Pitting, SCC, crevice, galvanic, MIC, erosion corrosion, weld decay, liquid metal embrittlement. n Corrosion protection measures: è Design taking into account the resistance of the different alloys in considered environment. è Selection of inhibitors. è Thermal treatments to control SCC and intergranular corrosion cracking. è Chemical cleaning (against PASCC) and passivation. è Electrical insulation from others metals to control galvanic corrosion.

96

FERRITIC AND MARTENSITIC STAINLESS STEELS

n 11-13% Chrome (type 405 and 410 S) Primarily used for clad lining n 11-13% Chrome (type 410) ferritic or martensitic stainless steel extensively applied for standard trim on process valves, pump impellers, vessel trays, tray components and exchanger tubes. Corrosion resistance è excellent resistance to sulfur at high temperature. è good resistance to hydrogen sulfide at low concentrations and intermediate temperatures.

97

AUSTENITIC STAINLESS STEEL Variables influencing the behavior of austenitic stainless steels in salted water: n Temperature: 50° C is accepted as the minimum temperature for the occurrence of stress corrosion cracking and pitting in slightly salted water (100-200 ppm). n Chloride content: In stress relieved structures, the maximum allowed chloride content to avoid pitting and crevice (below 50°C) is related to the alloy Type 304 316

Cl100 ppm 300 ppm

(these limits can be lower for some Licensor i.e. 50 ppm for UOP)

98

AUSTENITIC STAINLESS STEEL n Metallurgy selection is realized considering critical temperature which is the minimum temperature at which pitting or crevice may occur in ferric chloride solution. CSCC occurrence have to be considered separately.

99

COPPER ALLOYS n The materials Alloy type

Main composition

Aluminium bronze

92% Cu, 8% Al

Aluminium brass

77% Cu, 21% Zn, 2% Al, 0.04% As

Admiralty

71% Cu, 28% Zn, 1% Sn, 0.04% As

90-10 Cu-Ni

10% Ni, 1% Fe, Cu rem.

70-30 Cu-Ni

30% Ni, 1% Fe, Cu rem.

66-30-2-2 Cu-Ni

30% Ni, 2% Fe, 2 %Mn, Cu rem.

n The typical applications Seawater exchangers, water pipes, brackish water equipment.

100

COPPER ALLOYS nMain degradation mechanisms Erosion corrosion and impingement attack, stress corrosion cracking (in presence of 1 ppm of ammonia), selective leaching (Immune to hydrogen damage, and prevent biofouling) nCorrosion protection measures correct design according standards (BS MA18 in the graph). Check ammonia presence (UPSET conditions) Erosion ferrules (in Teflon or special Cu Ni alloys Cr modified)

Maximum seawater velocities for continuos flow conditions m/sec (ref.:BS MA 18)

101

TITANIUM ALLOYS The materials n Titanium is a reactive metal and as the other materials of the group forms spontaneously a superficial oxide film which ensure protection from the environment.

n The corrosion resistance is related to the stability and the continuity of the oxide layer (on-off corrosion behavior). n The reactive metal group is formed by (increasing by corrosion resistance): Titanium, Zirconium, Niobium and Tantalum. The corrosion behavior of these materials shows a large amount of similarities. ASTM grade Composition Gr 1,2,3,4 unalloyed (O and N content) Gr 7, 11 0.2 Pd Gr 12 0.8 Ni 0.3 Mo Gr 16, 17 0.04 Pd

102

TITANIUM ALLOYS n In which conditions: Seawater and desalinization plant, organic acid, in oxidizing and mildly reducing wet environments.

103

TITANIUM ALLOYS n Main contaminants and corrodents: Wet Fluorides (and halides in high concentration), methanol plus halides, nitric acid fuming, nitrogen tetroxide, gaseous water free halides, chlorinated solvents, concentrated reducing acids. n Degradation mechanism to be verified General corrosion, pitting, crevice, SCC, catastrophic oxidation, galvanic*, hydrogen embrittlement.

104

TITANIUM ALLOYS n Welding of titanium 1)

The weld of Chemically Pure and Pd alloys (ASTM gr. 1, 2, 3, 4, 7, 11, 16, and 17) shows the same corrosion resistance as the bulk material.

2)

Like all reactive metals at high temperature reacts strongly with atmospheric oxygen.

3)

Can be welded with GTAW or GMAW (same equipment used for SS 316 or nickel alloys).

4)

Argon or helium have to be be used to protect the weld in welding chamber (shop) or welding shoes (construction site).

5)

The weld quality verified easily for acceptance • Visual examination of “as weld” surface • hardness measurement is highly sensitive to oxygen pickup

105

NICKEL ALLOYS n Materials Alloy type Incoloy 800 Incoloy 825 Inconel 625 Inconel 600 Inconel 601 Hastelloy C-276 Monel 400

Main composition 33% Ni, 21% Cr, 40%Fe, 0.1% C, 1% Al+Ti 43% Ni, 22% Cr, 3% Mo, 2% Cu, 0.04% C, Fe Bal 43% Ni, 22% Cr, 9% Mo, 3.5% Nb, 0.04% C 76% Ni, 16% Cr, 8% Fe, 0,2 Cu, 0.08 C 60% Ni, 23% Cr, 16% Fe, 1% Al Cu, 0.1 C 57% Ni, 15% Cr, 16% Mo, 1% Fe, 0.02% C 66% Ni, 31% Cu, 1.4% Fe, 0.15% C

n Advantages: è Very resistant (as a function of specified type) to many environments è In aggressive reducing environments are mandatory selection n Disadvantages: è High cost (GdP will be not so happy!!! ) è Possible availability problems for some alloy

106

NICKEL ALLOYS

107

TYPICAL ENVIRONMENTS n Hastelloy C/C276, Inconel 625 è High resistance to acid (both oxidizing and reducing) è excellent resistance in chloride and/or H2S environment è High resistance vs underdeposit corrosion n Inconel 601, Incoloy 800 è High temperature resistance n Incoloy 825 è High resistance in chloride and/or H2S environment (lower than Hastelloy C-Inconel 625) è High resistance vs underdeposit corrosion (but can fail with NH 4Cl) n Monel è High resistance to hot alkalis è High resistance to acid (especially HF)

POLYMERIC MATERIALS n High molecular weight organic materials that can be formed into useful shapes. n Can be used for piping and equipment (thermosetters and thermoplastics) or for gaskets (elastomers)

Polymeric materials In refinery

Thermoplastics PE PTFE PVC

Thermosetters Glass fiber epoxy resin Glass fiber vynil ester ep. resin Glass fiber Poly ester ep. resin

Elastomers Viton (Flueelastomers) Kalrez (perfluoelestomers) NBR

108

THERMOPLASTICS n Are characterized by the softening with the increase of temperature and return to their original hardness when cooled (most are weldable). n Degradation mechanisms are different from metals: Swelling, softening, loss of mechanical properties, hardening and discoloration (no electrochemical mechanisms involved). Degradation may be caused by heat, solar exposure and UV. n For correct material selection and design are necessary: life time, temperature (!), environment and pressure. n Main couple material-environment are: PE(or PP)-water, PVC-mineral acids, PVDF-acids (at higher pressure and temperature).

109

Main Materials: Polyethylene (PE) Polypropylene (PP) Polyvinyl chloride (PVC-CPVC) Polyvinylidene Fluoride (PVDF) Teflon (PTFE)

THERMOPLASTICS n Advantages è Excellent chemical resistance to water environment, l PTFE can withstand practically all refinery environments below 200°C è Easy welding and installation (not for all) è No protection required in underground service n Disadvantages è Rapid decrease of properties with the temperature increase. è Chemical resistance to hydrocarbons è Not suitable in fire hazard area

110

THERMOSETTERS n Are characterized by the thermal degradation when exposed to heating. n Thermosetters are generally used as matrix for composite material. Glass is generally used as fiber. n Same degradation mechanism of thermoplastic: Swelling, softening, loss of mechanical properties, hardening and discoloration. Higher resistance than thermoplastics.

111

Main matrix Materials: Epoxy resin Vinyl ester epoxy resin Phenolic resin

THERMOSETTERS Main applications are: Firewater, cooling water, high pressure water lines (special types up to 280 Bar), sewer. Advantages è Excellent chemical resistance to aqueous environment è No protection required in underground service Disadvantages è Installation difficulties è Design and installation know how è Not suitable in fire hazard area è Sensitivity to vibrations and mechanical stresses

112

CATHODIC PROTECTION n History In 1824 Sir Humphrey Davy discovered that is possible to protect the copper of royal ships from marine corrosion by electrically coupling it with iron. n Basic Principle The metal dissolution is reduced trough the application of cathodic current that may originates from: è the corrosion of a less noble metal (sacrificial cathodic protection) è the conductive anode and ∆ V (current impressed cathodic protection) n Scope of CP applications: è Protect from wet and soil corrosion coated steel. è Allow the use of carbon steel avoiding the material upgrade. è Minimize the cost of CS coating maintenance.

113

CATHODIC PROTECTION Cathodic protection techniques n Sacrificial cathodic protection è Use of anodic metal l Magnesium (t< 40°C) l Zinc (t < 40°C) l Aluminum (Cl- > 1000 ppm or t > 40°C) è Anode connection with cathode l direct (economical) l trough a electrical resistance (improve the control and avoid under and over protection) è Reference electrodes l Allows monitoring and verification of corrosion for cathodically protected surfaces

114

CATHODIC PROTECTION Cathodic protection techniques n Impressed current cathodic protection è anode material l Ti Mixed metal oxide coated l High silicon iron l Ceramic electrodes è current generation l an external DC current source is necessary è reference electrodes l the use is mandatory in conjunction with current control system

115

CATHODIC PROTECTION n Design parameters è Temperature (important for anode selection) è pH è Chemical composition (Cl- and ions content) è Conductivity (high conductivity = aggressive condition) è Redox potential (i.e. oxygen content or other oxidizer presence) è Dimensions of the metal surface in contact with conductive electrolyte. (important! Water level on separators and oil tank internals) n With the parameters is possible to design the system: è which technique (sacrificial or impressed) è anode selection (Al, Mg, Zn, Ti or Fe-Si-Cr) è anode quantity (related to the required current) è anode distribution (related to the disposition of the surface to protect) è current system design (only for impressed current) è Insulation kits and resistance bonds disposition

116

CATHODIC PROTECTION n Typical applications è Underground and submerged steel surfaces (may be required by law). l l l l

Bottom tanks Underground and submerged Pipelines Jacket on offshore structures underground and submerged steel reinforced concrete structures

è Low temperature corrosion on the process side (cost evaluation). l Water tanks is preferable to cathodically protect internally lined surfaces l Water boxes (channels) of Thermal exchangers CP avoids cladding in Cu-Ni alloys in seawater exchangers l Water-oil separators CP avoids the use of stainless steel or ensure lower maintenance of internal lining

117

MATERIAL SELECTION AND CORROSION CONTROL IN REFINERY UNITS

MATERIAL SELECTION AND CORROSION CONTROL IN REFINERY UNITS

n DESALTER n ATMOSPHERIC DISTILLATION UNIT n VACUUM DISTILLATION UNIT n AMINE UNIT n HYDRODESULPHURIZATION UNIT n SOUR WATER STRIPPER UNIT

119

DESALTER THE DESALTER CAN BE THE SOURCE OR THE SOLUTION OF REFINERY’S PROBLEMS

120

DESALTER TIPICAL CORROSION AND FOULING PROBLEMS n Corrosion of water outlet lines (brine) n Fouling of inlet heat exchangers (generally due to oxygen and excessive temperature) n Remaining problems with desalter aren’t problems in the desalter itself (affect efficiency and downstream corrosion)

121

DESALTER - OPERATING GUIDELINES n Principal variables (by UOP) è wash water (4-10%) è Settling time (30-45min) è Temperature (90-150°C, high enough to dissolve sediments and salts) è Desalting chemicals (0.25 - 1 pint for 1000 barrels) è Alternating electric field è Valve è ∆P (7-15 psig) è Level n TARGET: DESALT TO LESS THAN 2 LBS/THOUSAND BARREL (PTB)

n Stripped Water should be used as wash water

122

DESALTER - OPERATING GUIDELINES

123

TEMPERATURE n Increasing temperature reduces viscosity and reduces settling time n Increasing temperature increases water solubility and water (including dissolved salt) carry over n Keep inlet heat exchangers below 150 °C è Reduce corrosion rates in exchangers è Reduce fouling in exchangers (minimizing salt precipitation)

ATMOSPHERIC DISTILLATION UNIT

124

ATMOSPHERIC DISTILLATION UNIT TYPICAL CORROSION AND FOULING PROBLEMS n HCl corrosion in the OVHD system èAmmonium Chloride èAmmonium Bisulfide n High

temperature

sulfur

corrosion n Naphtenic acid corrosion n Asphaltine/wax/polymer fouling n PASCC (300 series SS) n Wet hydrogen sulphide

125

ATMOSPHERIC DISTILLATION UNIT METALLURGY Use Chrome alloy (solid or lining for high Cr %) for sulfur resistance (according to McConomy curves) es. 1.25 Cr, 2.25Cr, 5 Cr, 9Cr, 12Cr in the bottom section of CDU tower and in the hot side of the heating train n Use Monel for HCl resistance in the top section of tower (for cladding and trays) and in the OVHD accumulator if condensation is expected n Use 90-10 Cu-Ni for Chloride resistance in the desalter brine n If Naphtenic acid are an issue (Note: check TAN number in cuts) è ALL 5 - 9 - 12Cr change to 317 or 316 with 2.5% min Mo (see also T and TAN) è Carbon steel in gas oil cut may also change to 317 or 316 with 2.5% min Mo è Must guard against PASCC of austenitic SS

126

ATMOSPHERIC DISTILLATION UNIT - MSD

127

NOTE: The indicated selection is not a guideline; it indicates only a possible choice among several solutions as a function of process conditions, corrosion mechanisms involved, lifetime and Prj requirements

ATMOSPHERIC DISTILLATION UNIT - OPERATING GUIDELINES

128

CAUSTIC INJECTION n Inject caustic if necessary to reduce chlorides in OVHD or to reduce TAN è Use fresh 2-3% caustic è Inject no more than 4 PTB è Inject to crude no hotter than 150 °C è Inject at least 5 feet upstream of equipment è and as close to desalter downstream as possible è Inject using a quill TAIL WATER pH Injection Quills n Operate between pH 5.5- 6.5 in tail water n Use a online pH meter n Automate control of corrosion inhibitor injection n Keep pH meter clean (filming amine, used as inhibitor, can dirty the instrument)

ATMOSPHERIC DISTILLATION UNIT - OPERATING GUIDELINES

WASH WATER IN OVERHEAD SYSTEM

n 20% of injected water not vaporized n water quality not critical, can recirculate DEW POINT n Run top of tower above dew point è Watch for “shock condensation” at point of recycle water inlet CORROSION INHIBITOR n Use corrosion inhibitor in the overhead line n May need to inject neutralizer and film former separately

129

VACUUM DISTILLATION UNIT

130

VACUUM DISTILLATION UNIT TYPICAL CORROSION AND FOULING PROBLEMS n H2S, CO2 corrosion in the OVHD system n High temperature sulfur corrosion wherever temperature exceeds 260°C n Naphtenic acid corrosion especially in heater outlet and transfer piping n Asphaltine/wax fouling n Polythionic acid SCC (300 series SS)

131

VACUUM DISTILLATION UNIT METALLURGY n Problem: traces of H2S, CO2, HCl in OVHD system è SOLUTION: use MONEL mesh for demister n Problem: traces of corrodents in Vacuum ejector è SOLUTION: use 316 internals n Problem: high temperature sulphur corrosion in bottom section of tower and in the heating train è SOLUTION: use chrome alloy (solid or lining for high Cr %) according to McConomy curves n Problem: Naphtenic acid corrosion (for cuts with TAN>0.5) è ALL 5 - 9 - 12Cr change to 317 or 316 with 2.5% min Mo n Problem: Polythionic acid SCC for sensitized material è follow the recommendation listed in NACE RP 0170

132

VACUUM DISTILLATION UNIT - MSD

133


AMINE UNIT

134

AMINE UNIT

n n

n

n

TYPICAL CORROSION AND FOULING PROBLEMS Tendency for corrosion varies with amine used, concentration and loading Acid gas corrosion è H2S, CO2 è Letdown valve into stripper è Overhead of stripper Heat stable amine salts (stronger than H2S) è Not stripped by heat in stripper è Inorganics (Cl-,SO4=, CN -, SO2) l Contaminants in feed è Organics (formic, acetic, oxalic) l Feed+oxygen l Pump seals, make up water è Areas: stripper bottom, reboiler, hot lean amine pipe Thermal degradation of amines è forms corrosive, acid species (especially in presence of oxygen)

135

AMINE UNIT

136

METALLURGY n Problem: Amine stress corrosion cracking and hydrogen damage è SOLUTION: PWHT (see also amine SCC) and use killed carbon steel n Problem: Acid gas corrosion (Letdown valve/piping into stripper and Overhead of stripper) è SOLUTION: use SS (304 or 316) n Problem: H2S, CO2in OVHD system è SOLUTION: use SS for tube condenser and OVHD accumulator (or CS HIC resistant) n Problem: sour water in the reflux pump è SOLUTION: use SS or duplex (as suggested by API 610)

AMINE UNIT - MSD

137


AMINE UNIT - OPERATING GUIDELINE n Limit amine temperature to 130 °F èReboiler steam less than 4.5 bar n Avoid acid gas flashing èUpgrade unavoidable

metallurgy

if

n Keep out oxygen from the system n Control fluids velocity n Filter è Typically 10-20 µm (smaller may help, i.e. 2 in series 15µ µm-5µ µm) è Partially filtration (10-15%) may be sufficient è Carbon filter to remove hydrocarbon and reduce fouling n Problems come from operating at maximum è Amine concentration è Circulation rate è Rich amine loading

138

HYDROTREATER

139

HYDROTREATER TYPICAL CORROSION AND FOULING PROBLEMS n Rust from tankage è oxygen in tank/transport è Plugs reactor bed n High temperature sulphur attack (sulphidation) n High temperature hydrogen attack (HTHA) n ammonium chloride in hydrogen recycle gas n ammonium bisulphide è Reactor Effluent Air Cooler (REAC) n Wet hydrogen sulphide n PASCC

140

HYDROTREATER

141

METALLURGY n Problem: Sulphidation and HTHA on reactor feed (generally from heater), reactor and effluent piping and exchangers è SOLUTION: use Austenitic SS (321 or 347). Use Chrome alloy for base material in case of cladded solution n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S on REAC, piping and accumulator è SOLUTION: use wash water and/or upgrade material to Incoloy 825, Inconel 625 or Ti. Austenitic 316 may be good to clad water phase on accumulator. CS is also possible with stringent velocity limits and monitoring n Problem: Polythionic acid SCC for sensitized material è follow the recommendation listed in NACE RP 0170

HYDROTREATER - MSD

142


HYDROTREATER - OPERATING GUIDELINE n Oxygen in feed (rust in tanks and polymerization fouling) è Gas blanket tankage l Nitrogen best l Natural gas may have air in it l Fuel gas good è Better bypass tankage section n Wash water è can be continuous (better) or discontinuous è Use balanced exchanger è 20% of injected water not vaporized è Velocity between 2.5 and 6m/s (9 for alloy) è Foul water < 8% NH4HS

143

SOUR WATER STRIPPER

144

SOUR WATER STRIPPER

TYPICAL CORROSION AND FOULING PROBLEMS n ammonium chloride n ammonium bisulphide è Reactor Effluent Air Cooler (REAC) n Wet hydrogen sulphide n Hydrogen damage

145

SOUR WATER STRIPPER METALLURGY n Problem: Sulfide Stress Cracking è SOLUTION: Apply requirements of NACE MR0103 where necessary n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S on REAC, piping and accumulator and reflux pump. Erosion corrosion on pump è SOLUTION: l Use intermittent wash water on REAC and upgrade material to Ti. l Use SS pipe (304 or 316 if chloride are expected) Maintain stream velocity below 15 m/s on piping. l Austenitic 316 may be good to clad accumulator l Use Hastelloy C (or alloy 20) on reflux pump to withstand corrosion and erosion-corrosion n Problem: Hydrogen damage on feed surge drum è SOLUTION: Use CS HIC resistant or CS SS cladded or lined CS (+CP)

146

SOUR WATER STRIPPER

147

METALLURGY n Problem: Wet H2S Corrosion, Acid gas on tube bottom feed exchanger, stripping column upper portion and inlet (after valve) è SOLUTION: Use solid SS (304 or 316 if chloride are expected) or cladding solution. n Problem: Galvanic corrosion exchanger, stripping column upper portion and inlet (after valve) è SOLUTION: Use solid SS (304 or 316 if chloride are expected) or cladding solution. n Problem: Ammonium chloride, Ammonium bisulfide, wet H 2S Erosion corrosion on charge sour water pump è SOLUTION: l Use Duplex or Superduplex SS to withstand corrosion and erosioncorrosion

SOUR WATER STRIPPER - MSD

148


Corrosion Mechanisms - Material Selection and Corrosion Control (Technip Italy)

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