Normas Texaco GEMS G-G-1 Material Selection Guide for Refinery Process Unit

DEC 97 MATERIAL SELECTION GUIDE FOR REFINERY PROCESS UNITS GEMS G-G-1

PAGE 1 OF 85©TEXACO GENERAL ENGINEERING DEPARTMENT

TABLE OF CONTENTS

PAGE

1. INTRODUCTION ....................................................... 3

2. COMMONLY USED ALLOYS ............................................... 3

2.1 Table of Nominal Composition ................................. 32.2 ASTM Designations ............................................ 32.3 Comparison of Materials ...................................... 3

3. REFINERY CORROSION AND OTHER FAILURES .............................. 10

3.1 Refinery Corrosion ........................................... 103.2 Creep, Stress Rupture, and High Temperature Metallurgical

Changes and Embrittlement .................................... 163.3 Mechanical Damage, Overloading, Overpressuring, and Fatigue .. 173.4 Incorrect or Defective Materials ............................. 20

4. MATERIAL SELECTION CRITERIA ........................................ 21

4.1 Predicted Corrosion Rate ..................................... 214.2 Hydrogen Attack .............................................. 224.3 Sulfidic Corrosion ........................................... 234.4 Naphthenic Acid .............................................. 244.5 Notch Toughness .............................................. 264.6 Stress Corrosion Cracking .................................... 27

4.6.1 General............................................... 274.6.2 Hydrogen Embrittlement and Hydrogen Cracking. Wet H2S

Cracking.............................................. 274.6.3 Caustic or Alkaline Cracking.......................... 314.6.4 Intergranular Corrosion and Cracking of Stainless

Steels - Polythionic Acid Cracking.................... 324.6.5 Chloride Stress Corrosion Cracking.................... 344.6.6 Amine Cracking........................................ 394.6.7 Ammonia Cracking...................................... 39

4.7 Scaling Resistance ........................................... 394.8 Fuel Ash Corrosion ........................................... 404.9 Elevated Temperature Strength ................................ 404.10 High Temperature Microstructural or Chemical Changes and

Embrittlement ................................................ 404.10.1 Hardening and Softening............................... 414.10.2 Grain Growth.......................................... 414.10.3 Graphitization........................................ 414.10.4 Temper Embrittlement and 885°F Embrittlement.......... 424.10.5 Sigma Phase........................................... 434.10.6 Carburization and Decarburization..................... 434.10.7 Liquid Metal Embrittlement............................ 43

4.11 References ................................................... 44

5. MATERIALS FOR PROCESS UNITS ........................................ 45

5.1 General ...................................................... 455.2 Crude Distilling Unit ........................................ 455.3 Hydrotreater - Hydrocracker .................................. 50



5.4 Catalytic Reforming Units .................................... 555.5 Fluid Catalytic Cracking Units ............................... 565.6 Alkylation Units ............................................. 605.7 Gasification Units ........................................... 615.8 Delayed Coking Units ......................................... 665.9 Sour Water Treating .......................................... 685.10 Sour Gas Treating Units ...................................... 695.11 Sulfur Recovery Units ........................................ 715.12 Tail Gas Treating Units ...................................... 715.13 References ................................................... 71

TABLES1 Nominal Chemical Composition of Commonly Used Alloys2 ASTM Designations of Commonly Used Alloys

FIGURES1 Operating Limits for Steels in Hydrogen Service2 Time for Incipient Attack of Carbon Steel in Hydrogen3 High Temperature Sulfur Corrosion - Hydrogen Free Environment3A Sulfur Corrosion Correction Factor4 Predicted Corrosion Rates - Hydrogen-Hydrogen Sulfide Environment5 Predicted Corrosion Rates - Hydrogen-Hydrogen Sulfide Environment6 Predicted Corrosion Rates - Hydrogen-Hydrogen Sulfide Environment7 Different Forms of Wet H2S Cracking8 Conditions Requiring Streee Relief of Carbon Steel in Caustic Service9 Stess Corrosion Cracking Austenitic Stainless Steels in Sodium Hydroxide

(From “Corrosion Resistance of Metals and Alloys.” Second Edition, Editedby F.L. Laque and H.R. Copson, 1965)

10 Stress Corrosion Cracking of 18-8 Stainless Steel in Chloride Solutions(From R.A. White, E.F. Ehmke. “Materials Selection for Refineries andAssociated Facilities.” NACE, 1991)

11 Relative 100,000 Hour Rupture Strength



1. INTRODUCTION

1. This guide is intended to give Engineering Department and refineryengineers background information on materials selection forrefinery process units.

2. Design of an individual unit may require some adjustment ofmaterials. Materials selected in the process unit section are basedon high sulfur crude. However, particular refineries should be ableto process a variety of different crudes. Unexpected high generalcorrosion can cause extensive unit downtime and product loss.

3. The information in this guide is general. More specific informationcan be found in industry references on hydrogen attack and sulfidecorrosion. API RP 571 “Recommended Practice for Recognition ofConditions Causing Deterioration or Failure” and “Corrosion inPetroleum Refining and Petrochemical Operations” by J. Gutzeit,R. D. Merrick and L. R. Scharfstein published in ASM MetalsHandbook, Ninth Edition, Volume 13, “Corrosion”, are goodreferences. Readers are encouraged to make comments they feel arewarranted based on their experience. Through information exchangeand experience, a consensus in various problem areas can be gained.

2. COMMONLY USED ALLOYS

2.1 Nominal Composition

See Table 1.

2.2 ASTM Designations

See Table 2.

2.3 Comparison of Materials

2. 3 .1 Carbon Steel

1. Reasons for Use: The most economical and readily availablematerial.

2. Problems

a. Low corrosion resistance.

b. Low high temperature oxidation and sulfidationresistance.

c. Low high temperature strength.

d. Low notch toughness.

e. Susceptible to stress corrosion cracking in aqueoussulfide, caustic, and amine solutions.

f. Susceptible to hydrogen attack and graphitization.

2. 3 .2 Low Alloy (Carbon - 0.5 Mo)

1. Reasons for Use

a. Higher elevated temperature strength than carbonsteel.

b. Years ago was believed to have increased resistance tohydrogen attack.



2. Problems

a. Low notch toughness.

b. Susceptible to graphitization and other problemsassociated with carbon steel.

c. Since 1970, a series of hydrogen attack cases of 0.5Moequipment has substantially reduced confidence in theposition of the Nelson curve (see Section 4.2,“Hydrogen Attack”) for this steel. C - 0.5Mo steel isno longer recommended for new or replacement equipmentin hydrogen service. Existing vessels operated inhydrogen service above carbon steel limits should berigorously inspected periodically. Texaco no longeruses this steel for new equipment.

2. 3 .3 Low Alloy (1.25Cr-0.5Mo, 2.25Cr-1Mo, 5Cr-O.5Mo, 9Cr-1Mo)

1. Reasons for Use.

a. Increasing Cr content yields increasing strength atelevated temperature, increasing oxidation,sulfidation (H2S or S), and hydrogen attackresistance.

b. Molybdenum improves elevated temperature strength andcreep resistance.

2. Problems

a. Increasing Cr content results in higher cost.

b. Welding becomes more difficult with pre- and post-heattreatment required.

2. 3 .4 AISI 4140, 4340

1. Reasons for Use: Increased strength for compressorimpellers and shafts.

2. Problems: Special welding and heat treating required tominimize sulfide stress corrosion cracking.

2. 3 .5 2.5 Nickel, 3.5 Nickel

1. Reason for Use: Increased low temperature notch toughness.

2. Problems: Increased cost and welding problems over carbonsteel.

2. 3 .6 Chromium Stainless Steel (Types 405, 410S, 410, 430, CA-15,CA-6NM)

1. Reasons for Use

a. Good resistance to non-acidic water solutions,sulfidation, oxidation, hydrogen attack.

b. Low susceptibility to chloride stress corrosioncracking.

2. Problems

a. Welding (especially with higher Cr content), poorelevated temperature strength.

b. Tendency to pit in aqueous chlorides and sulfides.

c. Embrittlement at 885°F.



d. Sigma phase problems with greater than 12.5% Cr.

e. Cost may be greater than austenitics.

f. CA-6NM easier to cast and weld than CA-15.

2. 3 .7 E-Brite XM-27

1. Reasons for Use: Much higher resistance to stresscorrosion cracking in chloride and caustic solutions thanthose of austenitic stainless steels.

2. Problems

a. Subject to embrittlement on extended exposure in 700°Fto 1060°F temperature range.

b. Strength falls off rapidly above 1000°F.

2. 3 .8 Cr-Ni Austenitic Stainless Steels (Types 304, 304L, 316, 316L,317, 317L, 321, 347)

1. Reasons for Use

a. Excellent corrosion resistance to many inorganic andorganic acids and alkalis.

b. Very good resistance to high temperature oxidation andsulfidation.

c. 316 and 317 SS have good resistance to naphthenic acidcorrosion.

d. 321 and 347 SS are more resistant to sensitization andintergranular corrosion and cracking (such aspolythionic acid cracking).

2. Problems

a. High cost.

b. Very high susceptibility to stress corrosion crackingin wet chlorides.

c. Very rapid intergranular corrosion and/or cracking(e.g., polythionic acid cracking) after sensitizationby heating in temperature range of 700°F to 1500°F.

d. L grades usually allow fabrication withoutsensitization but may sensitize after prolongedservice in the above temperature range.

e. For high temperature service, stabilized grades 321and 347 are recommended.

f. 321 may have poor strength at temperatures greaterthan 1100°F.

g. 347 has welding problems. 347 weld and weld overlaymust be of the correct composition to prevent sigmaphase formation and hot short cracking.

2. 3 .9 Cr-Ni Ferritic-Austenitic (Duplex) Stainless Steels (3RE60,2205, 2507, CD-4MCu)

1. Reasons for Use: More resistant to chloride stresscorrosion cracking than austenitic (300 series) SS.

2. Problems

a. Higher cost versus austenitic SS and poor weldability.



b. Cannot be used for long periods at temperatures aboveapproximately 570°F.

2. 3 .10 Alloy AL-6XN and Alloy 20Cb3

1. Reasons for Use: Increased resistance to acids andchemicals and much less susceptible to chloride stresscorrosion cracking than ordinary austenitics.

2. Problems: Increased cost and more difficult to weld thanordinary austenitics.

2. 3 .11 Incoloy 800

1. Reasons for Use

a. Good corrosion resistance (similar to ordinaryaustenitics).

b. Better resistance to chloride stress corrosioncracking.

2. Problems: Usually costs more than ordinary austenitics andsensitizes.

2. 3 .12 Incoloy 825

1. Reasons for Use

a. Increased resistance to acids and chemicals.

b. Much less susceptible to chloride stress corrosioncracking than ordinary austenitics.

2. Problems: Increased cost over austenitics.

2. 3 .13 Inconel 600

1. Reasons for Use

a. Good general corrosion and oxidation resistance.

b. Good elevated temperature strength.

c. Good resistance to chloride stress corrosion cracking.

d. Excellent corrosion resistance in caustic.

2. Problems

a. Poor sulfidation resistance above 1000°F.

b. Vulnerable to sensitization and intergranular crackingin some corrosives.

c. Cost.

2. 3 .14 Inconel 625

1. Reasons for Use

a. Excellent high temperature strength and corrosionresistance.

b. Very resistant to chloride stress corrosion crackingand sensitization.

2. Problems

a. Cost.

b. Availability

c. Poor sulfidation, resistance above 1000°F.



2. 3 .15 Hastelloy B

1. Reasons for Use

a. Excellent corrosion resistance in reducing acids, suchas HCl.

b. Good high temperature strength.

c. Very resistant to stress corrosion cracking.

2. Problems

a. Cost.

b. Availability.

2. 3 .16 Hastelloy C276

1. Reasons for Use

a. Excellent corrosion resistance in oxidizing acids.

b. Good high temperature strength.

c. Very resistant to stress corrosion cracking.

d. Resistant to sensitizing for much longer exposuretime.

e. Good corrosion resistance in reducing acids - secondmost corrosion resistant nickel alloy (after HastelloyB) in hydrochloric acid.

2. Problems

a. Cost.

b. Availability.

2. 3 .17 Monel

1. Reasons for Use

a. Good general corrosion resistance to many chemicals,such as hydrochloric and hydrofluoric acids, aqueoussulfide, and caustic.

b. Resistant to chloride stress corrosion cracking.

c. Excellent resistance to seawater.

2. Problems

a. Poor resistance to sulfidation over 400°F.

b. Embrittled by sulfur and heavy metals at lowconcentration during welding or heating.

c. Corroded rapidly by aqueous ammonia or ammoniumhydroxide at concentrations above approximately 3%weight.

2. 3 .18 Admiralty

1. Reasons for Use

a. Basic condenser tube material in cooling tower water.

b. Adequate resistance in aqueous sulfides.

2. Problems

a. Poor strength over 400°F.



b. Dealloys (Zn) in water service. Addition of smallamounts (0.03% to 0.05%) of arsenic (e.g., alloyC44300 per ASTM B111) substantially increasesresistance to dezincification.

c. Very susceptible to stress corrosion cracking in wetammonia.

d. Very rapid corrosion in ammonium hydroxide solutions.

e. Very difficult to weld.

f. Less resistant to seawater than aluminum brass andcopper - nickel.

2. 3 .19 Aluminum Brass

1. Reasons for Use: Similar to admiralty, except better inseawater, especially if fluid velocity is higher than 3feet/sec.

2. Problems: Similar to admiralty.

2. 3 .20 Naval Brass

1. Reasons for Use: Basic copper alloy tube sheet materialcompatible with admiralty and aluminum brass.

2. Problems: Similar to admiralty and aluminum brass.

2. 3 .21 Copper Nickel 90/10

1. Reasons for Use: Excellent in seawater.

2. Problems

a. Poor resistance to aqueous sulfides.

b. Susceptibility to stress corrosion cracking in wetammonia.

2. 3 .22 Copper Nickel 70/30

1. Reasons for Use

a. Excellent in seawater.

b. Less susceptible to stress corrosion cracking in wetammonia.

c. Good strength.

d. Good resistance to aqueous sulfides.

e. Weldable.

2. Problems

a. Higher cost than admiralty and aluminum brass.

b. Will dealloy (Ni).

2. 3 .23 Aluminum Bronze

1. Reasons for Use: Excellent resistance to seawater andweldable.

2. Problems

a. Cost.

b. May require heat treatment.



2. 3 .24 Aluminum and Its Alloys

1. Reasons for Use

a. Excellent corrosion resistance in:

(1) Atmospheric conditions (very resistant to rural,urban, and industrial atmospheres; lesserresistance to marine atmospheres).

(2) Fresh and cooling waters (except seawater).

(3) Hydrogen sulfide and carbon dioxide watersolutions.

b. Good resistance in concentrated (> 80%) nitric acidand organic acids (acetic, citric, tartaric, malic,fatty acids, etc.).

c. High notch toughness at very low temperatures, notsubjected to brittle fracture at cryogenictemperatures.

2. Problems

a. Corrodes rapidly in acid (pH < 4.5) and alkaline (pH >9.5) solutions.

b. Poor resistance in solutions containing considerableamounts of chlorides, such as seawater.

c. High sensitivity to galvanic corrosion (especiallywhen in contact with copper and ferrous alloys).

d. Very low strength at elevated temperature (over400°F).

e. Most aluminum alloys have poorer corrosion resistancethan pure aluminum. The latter has inadequate strengthfor many applications. Alclad 3003 alloy clad withAlloy 7072 (Al + 1% Zn) or with pure aluminum combineshigh corrosion resistance with improved mechanicalproperties.

f. Aluminum tubes currently have limited application inrefinery service because of fouling problems andpitting corrosion on the water side.

2. 3 .25 Titanium and Its Alloys

1. Reasons for Use

a. Combines comparatively high strength and very highstrength-to-weight ratio with outstanding resistancein many extremely corrosive environments, including:

(1) Seawater and other chloride salt solutions wherestainless steels undergo pitting and stresscorrosion cracking.

(2) Hypochlorites and wet chlorine.

(3) Nitric acid, including highly concentratedacids.

b. Titanium has very good low temperature strength.

2. Problems

a. Increased cost.



b. Welding must be done in inert atmospheres or the metalbecomes brittle due to absorbed gases (oxygen,nitrogen, and hydrogen).

c. Titanium is not a good high temperature material, asit is embrittled in:

(1) Hydrogen above 480°F.

(2) Air, oxygen, or nitrogen above 850°F.

2. 3 .26 Corrosion and Heat Resistant Cast Iron Ni-Resist

1. Reasons for Use

a. Good corrosion resistance in sour water, coolingwater, and sea water.

b. High resistance to high temperature scaling.

2. Problems

a. Low notch toughness.

b. Poor weldability.

3. REFINERY CORROSION AND OTHER FAILURES

3.1 Refinery Corrosion

3. 1 .1 General

Corrosion is the destruction or deterioration of materialcaused by a chemical reaction with the material’s environment.

Metal corrosion is principally caused by thermodynamicinstability of metals. In other words, the oxidized (corroded)state is more stable for the majority of metals than thereduced (metallic) state.

Protecting refinery equipment from corrosion is extremelyimportant. During operation, refinery equipment comes incontact with flammable hydrocarbon streams and toxic and/orexplosive gases, often at high temperatures and pressures. Suchcontact aggravates the potential for corrosion problems, which:

1. Substantially increases operating and maintenance costs.

2. Drastically reduces equipment safety and can lead toserious accidents, such as fires and explosions. In manyapplications with high potential for corrosion andcorrosion related failures of refinery equipment, safetyconsiderations are the major concern, exceeding economicconsiderations in importance.

3. 1 .2 Causes of Corrosion

Corrosion in refineries is not caused by processedhydrocarbons, which are mostly harmless with regards tocorrosion. Corrosion problems result from various contaminantscontained in the hydrocarbons, such as:

1. Water.

2. Hydrogen sulfide and sulfur.

3. Hydrogen chloride.



4. Carbon dioxide.

5. Naphthenic acids.

6. Polythionic acid.

7. Inorganic and organic chlorides.

8. Ammonia and ammonium bisulfide.

9. Cyanides.

10. Phenols.

11. Others.

Corrosive problems are also caused by process chemicals, suchas:

1. Sulfuric acid.

2. Hydrofluoric acid.

3. Phosphoric acid.

4. Caustic.

5. Amines.

6. Various chlorides from catalysts.

In addition, corrosion problems are caused by:

1. The atmosphere.

2. Cooling water.

3. Boiler feedwater.

4. Steam condensate.

5. Soil.

3. 1 .3 Common Types of Corrosion

1. General corrosion - thinning. Corrosion damage is spreadmore or less uniformly on the entire exposed metalsurface.

2. Local corrosion. Corrosion damage concentrates on localareas of the metal surface (e.g., pitting and crevicecorrosion). Local corrosion usually has a far greaterpenetration rate than general corrosion. Local corrosionis much more difficult to detect in a timely mannerthrough periodic inspections than uniform corrosion. Forthat reason, local corrosion is potentially moredangerous.

3. Galvanic or two-metal corrosion occurs when two alloyswith different electrode potentials are coupled in a watersolution, soil, or other electroconductive environment.The more electronegative metal becomes the anode of thecouple and undergoes accelerated corrosion. The morecorrosion resistant metal corrodes very little or not atall (cathodic protection is based on this principle).Galvanic corrosion can be a major problem in seawaterservice, cooling water, and other water containingenvironments. It may also occur in the atmosphere.

4. Stress corrosion cracking (SCC) is the fracture of alloysby a combination of corrosion and tensile stress. Failurefrequently occurs in a rather mild chemical environment



under a tensile stress well below the yield strength ofthe material.

In SCC, the stresses involved may be residual stresses inthe metal, such as from bending or welding, or from unevenheating or cooling. Applied stresses, such as workingstress from internal pressure or structural loading, alsocan be involved. In general, however, residual stresses areof prime importance in stress corrosion cracking. Onlytensile stress results in SCC. Compressive stress, on thecontrary, has a beneficial effect. Peening to introducecompressive stress has been used as a preventive measureunder some circumstances.

It has long been recognized that SCC is the most dangerousof the various types of corrosion failure of metals. SCCoccurs unexpectedly and is extremely localized. As a rule,SCC is accompanied by little change in the equipment wallthickness. Therefore, it is very difficult to predict theoccurrence of stress corrosion cracking and to takepreventive measures in a timely manner. SCC can causethrough fracture in very short periods of time (in the mostsevere cases in a day or even several hours).

Various kinds of SCC are described in Section 4.

5. Intergranular corrosion is localized attack at andadjacent to grain boundaries. The alloy disintegrates(grains fall out) and/or loses its strength.

Intergranular corrosion can be caused by noncorrosionresistant impurities at the grain boundaries or bydepletion of the alloying elements (responsible for thealloy corrosion resistance) in the grain-boundary area. Thelatter mechanism accounts for intergranular corrosion ofaustenitic stainless steels (polythionic acid cracking)described further in Section 4.

6. Hydrogen damage is a general term which refers tomechanical damage of a metal caused by the presence of, orinteraction with, hydrogen. It may occur at lowtemperature (e.g., hydrogen embrittlement in H2S watersolutions) and at high temperature (hydrogen attack inhigh pressure hydrogen). Hydrogen damage is describedfurther in Section 4.

7. Selective leaching is the removal of one element from asolid alloy by corrosion processes. The most commonexamples of selective leaching in refinery application aredezincification of brasses and denickelfication in copper-nickel alloys in cooling water systems.

8. Corrosion under insulation occurs when insulation or fireproofing is allowed to become wet. Corrosion of underlyingmetal surfaces becomes a serious problem with piping andvessels operating below 250°F because the metal is not hotenough to keep insulation dry during normal operation.

The best preventive approach is to keep insulation dry inthe first place. This means proper wrapping and caulking ofjoints. Metal surfaces near flanged connections shouldfirst be painted, since wetting of insulation, due toleakage, is likely to occur at such locations. Inaustenitic stainless equipment and piping, chloridecontaining insulation can cause stress corrosion cracking.



9. Erosion corrosion occurs when protective surface films ofcorrosion products are damaged or worn away such thatfresh metal is continuously exposed to corrosion. For thisreason, alloys of aluminum, chromium steels, and stainlesssteels are especially subject to attack, since they dependon a surface film for the resistance to corrosion. Bends,elbows, and tees of piping, pump cases and impellers,compressor blades, valve internals, agitators, baffles,thermowells, and orifice plates are subject to variousforms of erosion corrosion. In general, any increase invelocity will increase erosion corrosion, especially ifsuspended solids are involved. Flow turbulence at theinlet of heat exchanger tubes can result in rapidcorrosion of the first 2 or 3 inches of the tubing.

Erosion corrosion due to droplets of liquid suspended in avapor stream is a real problem in many refineryapplications. Known as impingement corrosion, this type oferosion corrosion occurs in overhead piping and condensersof distillation towers, when vapor velocities exceed 25ft/sec. The usual cause is water droplets that containdissolved hydrogen sulfide and hydrochloric acid. Areasmost likely to be attacked are elbows in overhead piping,condenser shell inlet nozzles, and condenser upper tuberows.

3. 1 .4 Mechanisms of High Temperature and Low Temperature RefineryCorrosion

For practical purposes, refinery corrosion can be divided intotwo categories: high temperature corrosion and low temperatureelectrolytic corrosion. The latter requires the presence ofliquid water.

High temperature corrosion starts at approximately 450°F andoccurs through the mechanism called chemical corrosion. Itrepresents the interaction of metal with the corrosiveenvironment, when oxidation of the metal and reduction of theoxidizing component - oxidizer (oxid.) of the environment occurin one step:

Me+Oxid. → MeOxid. (e.g., 4Fe+302 → 2Fe203 or Fe+H2S + FeS+H2)

(e.g., oxidation of steel in hot air, corrosion in hightemperature hydrogen sulfide.)

Corrosion mechanism in electrolytes, such as water solutions(low temperature refinery corrosion), is more complicated andis called electrochemical corrosion. The main feature ofelectrochemical corrosion is that ionization of metal (anodicreaction) and reduction of the oxidizer (cathodic reaction)occur in more than one step. In this case, overall corrosionreaction consists of at least two separate half cell reactions:

Anodic Reaction,Ionization of Metal Me Me + nen+→

Cathodic Reaction,Reduction of Oxid. + ne → Oxid.neOxidizer (e.g., 2H+ + 2e → H2 - hydrogen reduction



or O2 + 2H2O + 4e → 4OH- - oxygenreduction.)

Overall CorrosionReaction Me + Oxid. → Men+ + Oxid.ne

(e.g., Fe + H2SO4 → FeSO4 + H2 or2Fe + 2H2O + O2 → 2Fe+2 + 4OH- → 2Fe(OH)2

As shown in the above reaction equations, the electrochemicalmechanism includes the flow of released electrons from theanodic area to the cathodic area on the metal surface. Theanodic and cathodic reactions are separated from each other andoccur either at the same time on different areas of thecorroding surface (heterogeneous electrochemical mechanism) orat a different time on the same surface (homogeneouselectrochemical mechanism). In the latter case, the entirecorroding surface alternatively works at one moment as ananodic area and at another as a cathodic area.

In refinery corrosion, the heterogeneous electrochemicalmechanism with space division of anodic and cathodic reactionsprevails. Examples of electrochemical corrosion are corrosionin diluted acids, alkalis, seawater, other natural waters,cooling water, soil, atmosphere, H2S, and/or CO2 watersolutions.

It should be noted that in the temperature range between thehigh temperature corrosion starting point and watercondensation point (above which no electrochemical corrosion ispossible) corrosion practically does not occur.

3. 1 .5 Environmental Effects

The most important environmental factors influencing corrosionrate are content of oxygen and other oxidizers, pH, corrosiveconcentration, temperature, and velocity.

Except for passivated alloys (such as stainless steels,aluminum, and titanium), where formation of the surface oxidefilm drastically reduces the corrosion rate, increase of oxygenor other oxidizer content usually increases the rate ofcorrosion.

As a rule, decrease of pH (increase of acidity) substantiallyincreases rate of corrosion.

Concentration increases in the corrosive environment generallyincrease corrosion rates. However, corrosion in concentratedacids often is minimal because of small water content orformation of a protective film on corrosion products.

Temperature increases corrosion rates, as with almost allchemical reactions. Another temperature effect should beconsidered in refinery operations. Increased temperaturesincrease the amount of water in liquid hydrocarbon and vaporstreams. This means that more water condenses in downstreamdistillation towers or in overhead condensing systems. As aresult, corrosion occurs in equipment thought to be dry.



Corrosion by strong acids, such as concentrated sulfuric acidin alkylation units, is highly dependent on temperature. Carbonsteel can be used for these units primarily becausetemperatures are relatively low. Stainless steels can exhibit adrastic change in corrosion resistance as temperature reaches acertain level. This manifests itself as a sudden loss ofpassivity, causing the corrosion rate to increase by a factorof 100 or more.

Metal skin temperature rather than process stream temperatureshould be used to predict the corrosion rate.

Increase of flow velocity will cause removal of the protectivecorrosion product film and thereby raise the corrosion rate.

3. 1 .6 Corrosion Protection

Detailed descriptions of all corrosion preventive methods arebeyond the scope of this guide. The most commonly used methodswill be discussed briefly.

Proper metal selection is the most common method of corrosionprevention. Some of the “natural” alloy-corrosive combinationsare:

1. Stainless steels - nitric acid.

2. Nickel and nickel alloys - caustic.

3. Monel - hydrofluoric acid.

4. Hastelloys (Chlorimets)-hot hydrochloric acid.

5. Lead - dilute sulfuric acid.

6. Aluminum - noncontaminated atmospheric exposure.

7. Tin - distilled water.

8. Titanium - hot strong oxidizing solutions and highlyconcentrated chloride solutions.

9. Tantalum - ultimate corrosion resistance.

10. Carbon steel - concentrated sulfuric acid.

The above list does not represent the only material - corrosivecombinations.

There are two main mechanisms of metal corrosion resistance:

1. Thermodynamic stability when metal is chemically inert insome media (e.g., gold, platinum, copper).

2. Formation of a protective corrosion product film whicheffectively retards further corrosion (stainless steels,aluminum, titanium, etc.).

Relatively thin coatings of metallic, inorganic, and organicmaterials can provide an effective corrosion protective barrierbetween the metal and its environment. Metal coatings areapplied by electroplating, flame spraying (metallizing), hotdipping, cladding, weld overlaying, vapor deposition, etc.Inorganic coatings are applied by spraying, diffusion, orchemical conversion. Porosity or other defects in coatings can



result in accelerated localized attack on the base metalbecause of galvanic corrosion effect, etc.

Changing the environment to reduce corrosion includes loweringtemperature, changing velocity, removing oxygen or oxidizers,and changing concentration.

Inhibitors (substances which, when added in smallconcentrations to an environment, substantially decrease thecorrosion rate) and neutralizers (e.g., caustic and soda ash)are frequently added for corrosion control.

Certain design rules should be followed for best corrosionresistance.

1. Gaps, crevices, and other stagnant, difficult to accesszones should be avoided. Corrosive agents can accumulateand concentrate in such areas. If possible, small closedvoids should have provision of drain holes.

2. Tanks and other containers should be designed for easydraining and cleaning (sloped bottoms toward drain holes,etc.)

3. Systems should be designed to enable the easy replacementof components that are expected to corrode rapidly inservice.

4. Excessive mechanical stresses and stress concentrations incomponents exposed to corrosive mediums should be avoided.

5. Electrical contact between dissimilar metals should beavoided to prevent galvanic corrosion.

6. Sharp bends and other areas of rapid direction change inpiping systems should be avoided since they can promoteerosion corrosion.

7. Dissimilar metals, uneven heat and stress distributions,and other differences between points in the system shouldbe avoided since they may lead to corrosion damage.Conditions should be as uniform as possible throughoutentire system.

Cathodic protection and anodic protection are based on theuse of direct electric current either from a rectifier(impressed current system) or by contact with a moreelectronegative anodic metal (sacrificial anode system).

3.2 Creep, Stress Rupture, and High Temperature Metallurgical Changes andEmbrittlement

3. 2 .1 Creep and Stress Rupture

Creep and stress rupture strength are important mechanicalproperties for alloys used at high temperatures. Many steelsand alloys that have good high temperature corrosion resistancepossess insufficient mechanical properties for long-term use atelevated temperatures. Aluminum and its alloys are an example.

Creep is the continuous plastic deformation of a metal underapplied stresses below normal yield strength that occurs athigh temperature.



Stress rupture is the failure resulting from creep for anextended period of time.

Creep is the combined effect of temperature, stress, and timethat causes the formation of voids and fissures at grainboundaries and results in bulging or cracking. In some cases,it is an intergranular, brittle type of fracture with verylittle, if any, deformation prior to rupture. Hence, normalvisual inspection might not reveal an impending failure.

Creep in carbon steel becomes a problem above 650°F. Forinstance, long-term stress of 11,500 psi causes stress ruptureof carbon steel at 900°F. This can be compared to a short-termtensile strength of approximately 54,000 psi for the same steelat the same temperature.

Stress rupture failures in refineries are usually associatedwith fired heater tubes and fired boilers. Most of thesefailures are a result of overheating and local hot spots in thefurnace caused by faulty burners, inadequate control of furnacetemperature, and coke or scale deposits within the tubes.Bulging or hot spots are signs of impending failure.

3. 2 .2 High Temperature Metallurgical Changes and Embrittlement

In addition to creep and stress rupture, metals and alloysexposed to high temperature undergo microstructural andchemical changes that may cause substantial metal degradation.The most significant of such metallurgical changes aregraphitization, temper embrittlement, 885°F embrittlement, andsigma phase formation. All these changes, as well as chemicalchanges, such as carburization and decarburization, aredescribed in more detail in Section 4.

3.3 Mechanical Damage, Overloading, Overpressuring, and Fatigue

3. 3 .1 Mechanical Damage

Mechanical damage to refinery equipment is a common cause offailure. Typical examples are the misuse of tools and otherequipment, wind damage, and carelessness of handling whenequipment was moved or erected. Other types of loading onstructural columns that are normally designed for compressiveloading may lead to bending. Supports may have been damagedwhen used as anchors for winches. During earth moving work,underground pipelines and electrical conduits may have beendamaged if they were not carefully located and properlyidentified.

Flange faces and other machined seating surfaces may have beendamaged when not protected with covers or when not handled withcare. Material improperly thrown from truck beds may have beenbent, crushed, or cracked. Tubes of heat exchanger tube bundlesmay have been crushed if the bundles were not lifted withproper slings.

Equipment and structures are normally designed to withstand anyanticipated wind loading. During construction or repairs,however, wind damage may have occurred if components were notproperly reinforced. Loose sheets of metal, boards, and the



like may have been blown about by high winds if they were notproperly secured.

Wear or mechanical abrasion (erosion) is a significant problemin refineries and accounts for many failures. Catalyst movementin FCC units and coke handling in coking units are examples ofwear associated with refinery processes. Wear in pumps,compressors, and other rotating machinery is common in therefining industry.

Many parts designed for abrasion service are made of some gradeof austenitic manganese steel because of that alloy’soutstanding toughness coupled with good wear resistance.Hardenable carbon and medium alloy steels and abrasionresistant cast irons are also used.

A large assortment of alloys is available for abrasive service,including wrought alloys, sintered metal compacts, castings,and hard surfacing materials. They can be roughly classified,in descending order of abrasion resistance and ascending orderof toughness, as follows:

1. Tungsten carbide coating and sintered carbide compacts.

2. High chromium cast irons and hardfacing alloys.

3. Martensitic cast irons and hardfacing alloys.

4. Austenitic cast irons and hardfacing alloys.

5. Pearlitic steels.

6. Ferritic steels.

7. Austenitic steels, especially 13% manganese type.

Hardness is often thought to be a property that is indicativeof good wear resistance. It must, however, be considered withdiscretion when evaluating an alloy's suitability in abrasivesituations. Hardness should only be considered after itsrelation to a given service has been proven. Simple and widelyused hardness tests, such as Brinell or Rockwell, tell almostnothing about the hardness of microscopic constituents whichare very important to good wear resistance.

Cavitation damage is caused by the rapid formation and collapseof vapor bubbles in liquid at a metal surface as a result ofpressure variations. Calculations have shown that bubblecollapse can produce shock waves with impact pressuressufficiently high to produce plastic deformation in mostmetals. In brittle metals, cracking and metal loss occurs asgrains are torn out of the surface. Corrosive conditionsaccelerate cavitation damage. In refineries, cavitation occursmostly on the backside of pump impellers. Certain areas ofpiping components, such as elbows, can also become subject tocavitation damage. Vibration can also lead to cavitation.Damage is usually in the form of closely spaced pitting.Cavitation cold work hardens the surface layer of most metals.This can be detected by metallurgical examination of thedamaged part. Cavitation damage can be reduced by techniquessimilar to those listed for erosion corrosion.



3. 3 .2 Overloading

1. Overloading occurs when loads in excess of the maximumpermitted by design are applied to equipment. Hydrostatictesting of vessels can overload supporting structures dueto the excess weight applied. Excessive bending stressesmay be induced in vessel shells when pipe support bracketsare attached. Addition of piping to existing pipe supportsor piping that is left overhanging on supports may presentoverloading problems. Overloads can also occur where metalmembers have been weakened as a result of corrosion, wear,fire, or change in shape or position.

2. Thermal expansion and contraction cause many overloadingproblems, unless flexible connections are properlyprovided. Piping subject to thermal expansion may force acentrifugal pump or steam turbine out of line and warp theshaft, unless the pipe is anchored near the equipment.

3. 3 .3 Overpressuring

Overpressuring may be defined as the application of pressure inexcess of the maximum allowable working pressure of theequipment under consideration. With low excess pressure, thereis little chance of damage occurring. When excess pressures arehigh, failures causing loss of life and property can occur.Overpressuring causes buckling, bulging, ruptures, and splits.

3. 3 .4 Failure

Overloading and overstressing usually result in ductilefailure, which is accompanied by an appreciable amount ofdeformation before failure and, therefore, takes a lot ofenergy.

Brittle failure is rapid, often catastrophic, takes very littleenergy, and results in a fracture surface with a grainyappearance.

Brittle fracture occurs in metals:

1. Under rapid loading at temperatures below the ductile tobrittle transition temperature.

2. That have been embrittled by service in some environments(hydrogen, wet H2S, carburization, etc.) or some dangeroustemperature range (graphitization, temper embrittlement,sigma phase formation, etc.).

Brittle fracture results from a loss of ductility, whereuponthe steel is referred to as having low notch toughness or poorimpact strength. The loss of impact strength can result inbrittle fracture, not only upon actual impact loading but underconditions of more or less constant stress.

Brittle fractures, unlike ductile failures, occur withoutwarning. Lack of warning and the rapid and extensivepropagation of cracks account for the fact that such failuresare often catastrophic. Some brittle failures of tanks andpressure vessels have occurred during hydrostatic or pneumatictesting. For this reason, it is generally the policy to refrainfrom testing while ambient temperatures are low, particularlyif the testing medium is also cold. In any case, the test



pressure should be applied as slowly as practical in order toavoid sudden increases in stress.

3. 3 .5 Fatigue

Fatigue is the failure of a component by cracking after thecontinued application of cyclic stress. Below a definite stresslimit, cyclic stressing of a metal does not affect the materialand no cracking occurs, regardless of the passage of time. Thisstress limit is called the endurance limit or fatigue limit. Atstresses higher than the endurance limit, a crack initiates andis propagated by continued application of stress cycles.Eventually the component fails, usually from a single crack.Little deformation of the metal occurs, and the failure appearsto be brittle.

Generally, the endurance limit of steels is roughly 50% of thetensile strength. The endurance limit for non-ferrous alloysranges from 30% to 50%. Brittle steels are more likely to failby fatigue than ductile steels.

A large number of failures in refineries have been attributedto fatigue or corrosion fatigue. The latter occurs when localcorrosion (such as pitting) promotes the mechanical fatigue.Prime examples are reciprocating parts in pumps andcompressors, shafts of rotating machinery, boiler feedwaterdeaerator drums, etc.

Only tensile stress produces fatigue crack growth. Compressivestress will not cause fatigue.

Fatigue failure can be prevented by proper design, whichincludes eliminating stress raisers, using radii instead ofsharp corners, and avoiding stamping and other sharp-edgedmarks, as well as cold straightening bent parts that will laterbe subjected to in-service cyclic stress.

Other remedies are hardening the surface layer (e.g.,nitriding, carborizing) or eliminating tensile stress in thesurface layer (e.g., shot peening). Post weld heat treatment isalso helpful.

3.4 Incorrect or Defective Materials

Many failures in refineries are caused by incorrect or defectivematerials. Incorrect materials principally result from mix-ups bysuppliers. For example, during construction of one refining unit,approximately 30% of piping and fittings failed to meet specificationsin one way or another.

Often, suppliers may substitute what they consider to be an equivalentor “better” material than that specified. Suppliers do not realize thata stainless steel fitting is not necessarily an improvement over acarbon steel fitting, especially with regards to pitting corrosion orstress corrosion cracking.

The substitution of castings for wrought or forged shapes often leads toproblems. Casting defects, such as shrinkage, sand holes, or blowholesnot visible from the exterior of the casting, can create unforeseencracking and corrosion problems. Shrinkage cracks are often found in the



thinner sections where the cast metal cools faster. Sharp corners andabrupt changes in cross sectional area are stress raisers. Shrinkagecracks can occur at such points.

Discontinuities in wrought material are excellent crack initiators. Thediscontinuities may be laminations and crevices which can cause hydrogenblistering in certain applications.

To expedite repairs during a shutdown, material substitutions may benecessary. Often, the correct material simply cannot be obtained becauseof the long time required and unreasonably high “minimum quantity”purchase requirements. Intentional upgrading can also lead to problems(as in the above case of stainless steel fitting replacement).

To avoid costly problems arising from the use of incorrect materials,development of a metallurgical verification or positive materialidentification (PMI) program is recommended for each project. PMI shouldbe performed on alloy materials of the following types:

1. Plates and forgings and other pressure vessel components.

2. Piping.

3. Flanges.

4. Fittings.

5. Welds.

6. Valve parts.

7. Bolts and nuts.

8. Exchanger and heater tubes.

9. Elements of pumps and compressors.

The extent of testing may vary for different projects and may be from 5%- 10% to 100%.

Methods of testing include:

1. Portable optical emission spectrometer.

2. Portable X-ray fluorescence analyzer.

3. Chemical spot tests per ASTM STP 550, “Nondestructive RapidIdentification of Metals and Alloys by Spot Test”.

4. Laboratory analysis on coupons or drillings, using a laboratorygrade optical emission spectrometer, laboratory grade X-rayfluorescence analyzer, or wet chemical analysis.

4. MATERIAL SELECTION CRITERIA

4.1 Predicted Corrosion Rate

The predicted rate of corrosion during the service of designed equipmentand piping is an extremely significant factor that governs materialselection. Each type of equipment has a certain design life that isconsidered the minimum time that it must be in service beforereplacement. Texaco standards on equipment design life are:



DESIGN LIFE OF EQUIPMENTEquipment Type Life, Years

Piping, Small (less than 18 inch NPS) 10Piping, Large (18 inch NPS and larger) 20Furnace Tubes 10Vessel Shells (including nozzles) 20Internals (non-removable) 20Internals (removable) 10

Trays 10Exchanger Shells (including nozzles) 20Exchanger Tubes: Carbon Steel 5 Alloy Material 10Air Cooled Exchangers (including headers, tubes) 10Pump Casings 20

The exact corrosion rate expected cannot be easily determined for manyapplications. Approximate, reasonably conservative values are thereforeused. Based on the approximate predicted corrosion rate, the corrosionallowance (CA) that is needed to provide a designed equipment item withthe desired design life can be selected. For example, a designedpressure vessel with an expected corrosion rate of 12 mils per year or12 mpy (1 mil = 0.001 inch) should have a minimum CA of 12 mpy x 20years, which equals 240 mils or 0.24 inch.

Typical CAs are:

1. Carbon steel pressure vessels - 1/8 inch and 1/4 inch.

2. Carbon steel and low alloy piping - 1/16 inch, 1/8 inch, and 3/16inch.

3. Stainless steel piping - as low as 1/32 inch.

If the above CAs do not provide the required design life, more corrosionresistant material or other anticorrosive methods (such as cladding,coatings, inhibitors) should be used. The above rule may have someexceptions.

4.2 Hydrogen Attack

Gaseous hydrogen does not appreciably permeate steel at atmospherictemperature. However, at elevated temperatures and pressures, molecularhydrogen dissociates into atomic form, which then permeates the steel.Within the steel, hydrogen reacts with iron carbide or dissolved carbonto form methane, which causes decarburization and cracking. The chemicalreaction is as follows:

C(Fe) + 2H2 → CH4

Where:

C(Fe) indicates carbides or dissolved carbon.

The methane formed cannot diffuse out of the steel. Accumulation ofmethane in internal voids results in the development of high stressesthat ultimately fissure, crack, or blister the metal. This accumulation,which affects the load carrying ability of the equipment, is called



hydrogen attack. The addition of chromium and molybdenum to steelincreases carbide stability and resistance to hydrogen attack.

Early data on hydrogen attack was plotted by George Nelson of ShellDevelopment. The “Nelson Curves” have been widely accepted as designcriteria. Nelson's work was assumed by the American Petroleum Instituteand is discussed in API Publication 941, “Steels for Hydrogen Service atElevated Temperatures and Pressures in Petroleum Refineries andPetrochemical Plants”. Laboratory and operational data are plotted toshow safe operating conditions of temperature and hydrogen partialpressure for carbon and various low alloy steels (Figure 1). A secondcurve (Figure 2) shows the effect of time on hydrogen attack for carbonsteel.

It should be noted that, in this edition, the curve for C - 0.5Mo steelhas been removed from the Nelson Curves Graph (Figure 1). Since 1970, aseries of unfavorable service experiences has reduced confidence in thissteel. The current edition of API 941 cautions users about a potentialdanger of using C - 0.5Mo steel above the Nelson Curve for carbon steeland recommends rigorous periodic inspection (UT examination) for suchapplications. Texaco no longer uses this steel and instead utilizes1.25Cr-0.5Mo with the additional requirement of a minimum chromiumcontent of 1.25%.

Texaco's normal design practice is to stay 50°F below the curve for aparticular steel. In vertical sections of the curve, Texaco normallyuses an equivalent safe hydrogen partial pressure.

It should also be indicated that hydrogen attack has been found in boththe gas phase and the all-liquid hydrocarbon phase that is inequilibrium with the gas hydrogen phase.

The hydrogen attack curves form the basis for material selection forhydrogen processing units. Materials may need to be upgraded, clad, oroverlaid for corrosion protection. The upgraded material or backingsteel must be resistant to hydrogen attack at the process designconditions. (Maximum operating temperature shall be 50°F below the steelNelson curve.) In no case shall the mechanical design temperature beabove the Nelson curve.

4.3 Sulfidic Corrosion

Corrosion by various sulfur compounds at temperatures above 500°F is acommon problem in many petroleum refining processes. The corrosionmechanism is believed to include conversion of sulfur compounds tohydrogen sulfide, followed by reaction of H2S with steel. Corrosivity ofsulfur compounds generally increases with temperature.

Corrosion control depends on the formation of a metal sulfide film thatbecomes much more protective in the presence of chromium. Thus, theaddition of chromium increases steel resistance to high temperaturesulfidic corrosion.

For the purpose of materials selection, high temperature sulfidiccorrosion is broken into two parts, depending on whether or not hydrogenis present.

Sulfidic corrosion without hydrogen occurs primarily in variouscomponents of crude distillation units, catalytic cracking units, and



hydrotreating and hydrocracking units upstream of the hydrogeninjection.

Prediction of sulfidic corrosion rate in a hydrogen free environment canbe made based on the modified McConomy curves (Figure 3), whichsummarize multiyear refinery experience. The corrosion rates found onthe curves should be multiplied by a correction factor shown on Figure3A for process streams with various sulfur contents. As the figuresshow, doubling the sulfur content can increase the corrosion rate byapproximately 30%.

Plant experience has shown that the sulfidic corrosion rate in theabsence of hydrogen starts to decrease as temperatures exceed 850°F. Thedecrease can be attributed to the formation of a protective coke layerand decomposition of reactive sulfur compounds (such as H2S).

Sulfidic corrosion in the presence of hydrogen is typical forhydrotreating and hydrocracking operations. Hydrogen increases theseverity of high temperature sulfidic corrosion, presumably byconverting organic sulfur compounds in feed stocks to hydrogen sulfide.

Modified Couper-Gorman corrosion rate curves, which are being used forelevated temperature sulfide corrosion in hydrogen containing processes,are shown on Figures 4, 5, and 6.

The estimated corrosion rate, services involved, and desired design lifedetermine the material and its corrosion allowance. Rates of up to 10mils per year are usually considered acceptable. However, considerationmust be given to potential downstream pressure drop problems that resultfrom scale buildup. Many times, corrosion rates can be tolerated fromthe mechanical standpoint, but equipment fouling and/or pressure dropproblems for units with long anticipated runs must be considered.

While these curves form a reasonable basis to select materials, otherdata, such as sulfur distribution and evolution curves for a particularcrude, may be very helpful.

4.4 Naphthenic Acid

Naphthenic acids occur naturally in some crude oils. Duringdistillation, these acids tend to concentrate in higher boiling pointfractions such as heavy atmospheric gas oil, atmospheric resid, andvacuum gas oils. The acids may also be present in vacuum resid, butoften many of the more corrosive ones will have distilled into thevacuum sidestreams. Lower boiling point streams are usually low innaphthenic acids.

Typical problem areas are in crude distillation units, heater outlets,transfer lines, atmospheric and vacuum towers, and side streamstrippers. Naphthenic acid problems may be aggravated by leakage ofoxygen into the vacuum systems.

Appearance of Naphthenic Acid Corrosion: Naphthenic acid corrosion andH2S sulfidic corrosion occur at roughly the same temperature ranges.However, they can be easily distinguished from each other by theappearance of the corrosion. Naphthenic acid corrosion generally hascavities and craters with sharp edges or channels and grooves withlittle or no corrosion product on the surface. Such corrosion isgenerally the severest or localized to turbulent areas. The surface ofthe metal is scale free because the naphthenic acid corrosion product,



iron naphthenate, is soluble in hot hydrocarbons. In contrast, when H2Scorrosion is dominant, a thick, adherent, protective iron sulfide filmis present, and the metal surface is smoothly and uniformly corroded. Inmost cases, either naphthenic or H2S corrosion is observed with noevidence of the other mechanism being present as if one mechanism isdominant to the exclusion of the other. However, under thresholdconditions, in some cases, corrosion in turbulent areas is observed thatis smooth in appearance without an adherent, protective FeS film.Corrosion rates in such cases are far greater than would be predictedfor H2S corrosion alone. Naphthenic acid can be considered a primarycontributor to such corrosion.

Temperature: Naphthenic acid corrosion typically has been observed inthe 450°F to 750°F temperature range. Above 750°F, the naphthenic acidseither break down or distill into the vapor phase. Naphthenic acidcorrosion occurs only where liquid phase is present. The corrosionincreases with temperature up to the acid’s decomposition and/orcomplete vaporization temperature.

Sulfur Content in the Crude: At low temperatures, certain sulfurcompounds may reduce the severity of naphthenic acid corrosion. At suchtemperatures, the sulfide film may offer some degree of protection fromthe naphthenic acid corrosion provided the velocities are not high. Athigher temperatures, the presence of naphthenic acids increases theseverity of sulfidic corrosion. It appears that the presence of thenaphthenic acids disrupts the sulfide film thereby promoting sulfidiccorrosion on alloys that would normally resist this attack.

Naphthenic Acid Content is a very important factor in naphthenic acidcorrosion and is generally expressed in total acid number (TAN) orneutralization number that is the amount of KOH in milligrams requiredto neutralize 1 gram of stock.

Until recently naphthenic acid corrosion would have been considered apossibility at neutralization numbers greater than 0.5 for the wholecrude or any gas oil range cuts. Most serious naphthenic acid problemswere believed to occur with neutralization numbers greater than 1.0.

But both ASTM methods being used for naphthenic acid contentdetermination, ASTM D974 and ASTM D664, do not differentiate betweennaphthenic acids, phenols, carbon dioxide, hydrogen sulfide, mercaptans,and other acidic compounds present in the oil. In addition, the twomethods, when compared, do not yield the same results. ASTM D664 yieldsTAN numbers that are 30% to 80% higher than ASTM D974. However, theseASTM methods are the only tests that produce values that aresufficiently documented at present to permit comparison of crudecorrosivity. Thus, prediction of crude corrosivity based on the TANalone could be highly misleading.

For assessment of plant corrosion effects, the naphthenic acid contentneeds to be determined for each cut in order to predict exactly wherethe acids will concentrate during the distillation of crude. Theisolation and analysis of naphthenic acids from crude oil may beperformed adequately with methods, such as UOP 565 and UOP 587, bychromatographic separations, or other available analytical techniques.Nalco has a technique that will provide the NAT (naphthenic acidtitration) number from a crude or side cut sample. The NAT number is nowappearing more frequently in the literature as the true measure ofacidity to better characterize the naphthenic acid corrosivity.



Velocity: The flow regime has a significant effect on naphthenic acidcorrosion. The higher the acid content, generally, the greater thesensitivity to velocity. In some cases, it appears possible to obtainvery high corrosion rates even at relatively low levels of naphthenicacid content (i.e., TAN ≈ 0.3) and low sulfur content when combined withhigh temperature and high velocity. Fluid velocity has long been used asthe parameter for comparing flow in pipes, heater tubes, and heatertrays and also for comparing laboratory data to the field. However,fluid velocity has been found to lack predictive capabilities and isbeing replaced by parameters related to fluid flow, such as the fieldshear stress and the Reynold’s number. Field shear stress, rather thanvelocity, is the parameter directly proportional to corrosion throughremoval of the normally protective films. The field shear stress isproportional to all of the following:

1. Density and viscosity of fluid and vapor in pipe at a specifiedtemperature.

2. Degree of vaporization in the pipe.

3. Pipe diameter.

Materials: The materials most vulnerable to naphthenic acid corrosionare carbon steel (corrosion rate may be as high as 1,000 mils per year)and the iron-chrome (5%-12% Cr) alloys commonly used in corrosiverefining services. 12% Cr may experience corrosion rates greater thanthose of carbon steel. The molybdenum containing austenitic stainlesssteel (Type 316 or Type 317 SS) are required for resistance to greateracid concentrations. It has been found that a minimum Mo content of 2.5%is required in Type 316 SS to provide the best resistance to naphthenicacids.

Naphthenic acid corrosion can be controlled by blending crude oils thathave high neutralization number with other crude oils. Blending isdesigned to reduce the naphthenic acid content of the worst sidecut.When blending is insufficient to prevent attack, affected areas can bealloyed with Type 316 or 317 SS.

4.5 Notch Toughness

Selection of materials for pressure containing parts must adequatelyconsider notch toughness requirements. Notch toughness is a measure ofthe ability of a material to absorb rapid or impact loading withoutfracturing. Significant factors are the type of steel used, theoperating and ambient temperatures, and the required thickness. Certaincarbon steels and low alloys have considerably better notch toughness atroom temperature than others. The lower the temperature and the thickerthe equipment, the more emphasis must be placed on notch toughness.Notch toughness is typically measured by Charpy V-notch test bars. Thebar is broken by impact at a specified temperature, and the energyrequired to fracture the bar is recorded. Although considerations canbecome very complex, energy absorption greater than 15 ft-lb to 20 ft-lbat a specified temperature is usually considered adequate to minimizenotch toughness problems that could lead to brittle failure. Somecritical pressure equipment items, such as high temperature, highpressure hydrogen reactors may have a more stringent energy absorptionrequirement (e.g., 40 ft-lb). Because of an increasing awareness ofbrittle failure, notch toughness criteria are becoming more significantin the selection of steels for pressure containing parts.

In designing equipment to operate at low temperatures (especially in thesubzero range below 32°F or 0°C), problems associated with notch



toughness becomes extremely important. The majority of steels and alloysshow a tendency toward a sharp decrease of notch toughness and anincrease in the possibility of undergoing brittle fracture at theselower temperatures. The list of steels used at very low, subzero, andcryogenic temperatures includes (in the order of increasingly lowtemperature notch toughness):

2.5% nickel A 203 GRA&B, A 334 GR7, A 333 GR73.5% nickel A 203 GRD&E, A 334 GR3, A 333 GR35% nickel A 6459% nickel A 353, A 333 GR8, A 334 GR8

and austenitic stainless steels. Iron - nickel alloy Invar M63 (36% Ni),as well as some aluminum and titanium alloys, also possess high valuesof low temperature notch toughness.

4.6 Stress Corrosion Cracking

4. 6 .1 General

Most materials used in refinery service can fail due to stresscorrosion cracking. Failures may occur without prior warning,and potential problems are often difficult or impossible topredict. Stress corrosion cracking results from a combinationof stress and corrosive environment. Many materials have highcracking susceptibilities in certain environments. Sincerefinery processes often contain the necessary corrosiveenvironment, considerable emphasis must be placed on selectionof materials and on how the material is fabricated and used.

Several types of stress corrosion cracking are brieflydescribed. It is important for designers to recognize that manyof the problems can be minimized by controlling the environmentand fabrication of equipment.

4. 6 .2 Hydrogen Embrittlement, Hydrogen Cracking, and Wet H2S Cracking

Hydrogen embrittlement affects many materials. In refineryservice, it normally causes problems with carbon steel, lowalloys, and chromium stainless steels. Cracking results fromhigh stresses and hydrogen pickup due to acid or wet hydrogensulfide corrosion and is often promoted by cyanides in the FCCUgas recovery streams. The most widespread is wet H2S cracking.

Hydrogen sulfide is a relatively mild acting corrosive tocarbon steel. General corrosion rates tend to be not very high.However, during the mild corrosion process, considerableamounts of hydrogen can be liberated. The hydrogen can haveseveral significant, detrimental effects on the refineryequipment metal.

Atomic hydrogen (H) and molecular hydrogen (H2) are produced inthe corrosion reaction of steel with aqueous H2S as follows:

Fe + H2S → FeS + 2H followed by 2H → H2

Under ordinary conditions, molecular hydrogen produced by theabove corrosion reaction harmlessly evolves away. If hydrogensulfide is present, it acts as a negative catalyst anddiscourages the reaction 2H → H2. This permits the atomichydrogen to accumulate on the metal surface and penetrate steel



where its presence in the crystal structure affects mechanicalproperties. Other “poisons” that promote the entrance of atomichydrogen into steel are cyanide, phosphorous, antimony,selenium, and arsenic ions. Atomic hydrogen is much smallerthan molecular hydrogen. As a result, only atomic hydrogen candiffuse through the steel's microstructure. Upon reachinglattice flaws, nonmetallic inclusions, and other void typedefects, the atomic hydrogen can form molecular hydrogen,causing a pressure build up that is sufficient to produce localruptures and fissuring.

Aside from corrosion, sources capable of charging a steel withhydrogen are acid pickling and cleaning operations, plating,welding, and cathodic protection.

Hydrogen charging in wet H2S may cause hydrogen embrittlementor cracking. The latter involves four types of mechanisms:sulfide stress cracking, hydrogen blistering, hydrogen inducedcracking, and stress oriented hydrogen induced cracking (Figure7).

Hydrogen embrittlement occurs during the advanced stage ofhydrogen saturation of steel. The structure becomes brittle asa result of the many strains imposed on the lattice structureby the presence of hydrogen. In such cases, the structure willfracture instead of deforming when subjected to stress.Harmless micro-cracks introduced by fabrication, heattreatment, or welding exist in most structures. In the absenceof hydrogen, they are harmless. In the presence of hydrogen,sudden brittle failure at low stress levels can result. Ingeneral, harder, higher strength steels are more susceptible tohydrogen embrittlement than lower strength steels.

Sulfide stress cracking (SSC) is cracking attributed tohydrogen in high strength, low ductility microstructures thatcan be identified by high hardness. It is highly dependent on asteel's composition, microstructure, strength, residual stress,and applied stress levels. Small, localized hard zones in weldsand weld heat affected zones can initiate SSC, even if bulkmaterial hardness is quite low. Sulfide stress cracking is alsoseen in hardened components, such as valve trim and compressorsprings, that are exposed to wet sulfide environments.Resistance to SSC can be provided by tempering or postweld heattreatments, which reduce hardness to 200 Brinell HardnessNumber (BHN) or lower. Postweld heat treatment reduces residualstresses and tempers the microstructure, thereby providing SSCresistance. If cracking of standard 12% chromium steel valvetrim is a problem, a change to austenitic stainless steel canbe considered. High strength bolting can be given a modifiedtemper to reduce hardness and, thereby, the tendency to crack.

Hydrogen blistering occurs when hydrogen atoms that diffuseinto the steel enter any available internal defects (such asinclusions or voids). These hydrogen atoms will combine thereto form hydrogen gas (H2) that cannot diffuse out of the steel.Blistering occurs because of the buildup of local hydrogen gaspressure in these internal defects. Elongated MnS stringersfound in older pressure vessel steels and banding of pearliteand ferrite phases both act as sites for absorbed hydrogenaccumulation and thus the initiation of blisters. Very often,



blisters become apparent on the metal surface. Increasingblister growth can produce tears to the surface and result in aloss of pressure containing capability.

Hydrogen induced cracking (HIC) also results from hydrogen gasbuild up, but it produces only internal (subsurface) cracks andsmall blisters without showing up at the surface. In manycases, cracking is described as stepwise cracking. Likeblistering, HIC is not stress dependent.

Stress oriented HIC (SOHIC) can be considered a special case ofHIC, in which a stack of small fissures that are formed in thesteel are oriented perpendicular to the applied stress. Thesmall fissures can become linked and form a leak path throughthe thickness of the steel which makes this failure moredangerous. SOHIC is often found adjacent to a weld where theresidual stresses are high, because SOHIC is stress dependent.

Hydrogen embrittlement and cracking affects pressure vessels,piping, and tanks, as well as pumps, compressors, valvesprings, impellers, and hardware.

Remedial actions include reduction or elimination of hydrogenactivity. This can be done by using alloy or alloy cladmaterials or nonmetallic coatings resistant to hydrogenproducing corrosion or by inhibiting the corrosion process.

For stress dependent failures, such as sulfide stress crackingor SOHIC, post weld heat treatment and hardness limitation (notto exceed 200 Brinell) are very beneficial. Texaco guidelinesmandate PWHT for pressure vessels, heat exchangers, aircoolers, pumps, and compressors in wet H2S service. Service isconsidered wet H2S if it contains free liquid water and H2Sconcentration equal to, or exceeding, any of the followingvalues:

a. Partial pressure in vapor phase of 0.25 psi.

b. Content in water phase of 50 wppm.

c. Content in liquid hydrocarbon phase of 250 wppm.

Hardness after PWHT shall not exceed 200 Brinell.

Hydrogen blistering, HIC, and SOHIC may be controlled bylimiting the sulfur content in steel (to decrease the amount ofMnS inclusions where gas hydrogen tends to accumulate) andshape control of these inclusions. Based on this approach, socalled “HIC resistant” steels were developed. The term “HICresistant” is used by manufacturers and users to denoteconventional grades of steel (e.g., ASTM A 516-70) that havebeen metallurgically processed to enhance their resistance toHIC. Such processing typically includes ultra-low sulfur levels(i.e., < 0.002 weight % sulfur), normalizing heat treatments tomodify the hot rolled microstructure, and possibly Ca additionsto produce sulfide shape control. Shape control is important inthat it produces sulfides of spherical morphology that reducelocalized stresses in the vicinity of the inclusion, comparedto the elongated stringers found in conventional steels. Thesesteels are often tested to evaluate HIC resistance usingconventional or modified NACE TM0284 methods for the purposes



of lot acceptance or for supplemental information. These steelstypically have improved resistance to HIC as compared toconventional steels. However, the latest CLI Internationalresearch showed that the currently used HIC resistant steels insome cases are more susceptible to SOHIC than conventionalsteels(Cayard, et al, see references). CLI Internationalcurrently recommends using low sulfur conventional steels inthe applications that require the use of HIC resistant steel.The sulfur content should be 0.005% to 0.010%. S lower than0.005% may promote SOHIC.

For the purpose of wet H2S cracking protection, the affectedrefinery equipment is divided into 3 categories.

Category 1 Service

H2S concentration is 50 to 2,000 ppmw in water phase, whichcorresponds to partial pressure of H2S gas of 0.25 psi to 10psi.

No known cyanide compounds or cyanide concentration less than20 ppmw.

No previous experience of significant blistering, HIC, orSOHIC.

Protective measures.

Pressure vessels: Killed carbon steel, PWHT, hardness not toexceed 200 Brinell.

Piping: Killed carbon steel, hardness not to exceed 200Brinell.

Category 2 Service

H2S concentration is above 2,000 ppmw in water phase or 10 psiin gas phase.

Presence of hydrogen cyanide or other cyanide compounds (morethan 20 ppmw in water phase).

Previous experience shows significant blistering, HIC, or SOHICproblems.


Pressure Vessels: Killed carbon steel normalized or quenchedand tempered.

Sulfur content in steel 0.005% to 0.010%, maximum phosphoruscontent of 0.010%.

Each plate should be 100% UT in accordance with ASME SA-578-S1.1 with level III acceptance standards.

PWHT, hardness not to exceed 200 Brinell.



Piping: Killed carbon steel, hardness not to exceed 200Brinell.

Category 3 Service

Acidic aqueous phase with pH value below 4.5.

High concentrations of acid gases H2S and CO2.

History of high rate corrosion and significant cracking and/orblistering.

Equipment in critical service when failure can cause explosionsand fire.


Pressure Vessels: Corrosion resistant liners, such as 304L SSor 316L SS cladding and weld overlay, organic coatings, etc.

Piping: Corrosion resistant materials, such as 304L or 316L SS.

In some cases, sulfide stress cracking of carbon steel pressurevessels resulted from the use of certain welding wire-fluxcombinations during fabrication. Some of the welding proceduresresulted in abnormally high weld hardness and caused unexpectedsulfide cracking failures. As a result, certain weldingrestrictions have been placed on fabricators of carbon steelequipment.

Very specific heat treating restrictions have been placed oncompressor manufacturers to limit the yield strength ofimpellers and other highly stressed parts to 90,000 psi. Theadded requirement of utilizing a heat treatment, such that nountempered martensite is formed, greatly minimizes potentialsulfide stress cracking problems.

4. 6 .3 Caustic or Alkaline Cracking

Caustic stress corrosion cracking is a result of high stressesin caustic or other alkaline environments. Cracks areintergranular. Most materials used in refinery applications canhave cracking problems. Cracking usually takes place in causticservice and boiler applications. Alkaline cracking occurs ifconditions lead to partial dissolution or breaks in normallyprotective corrosion product film on the metal surface.Cracking is not related to weld hardness.

Temperature-related caustic cracking occurs for carbon steelabove a temperature range of 120°F to 180°F (Figure 8) and forstainless steels above a temperature range of 220°F to 400°F(Figure 9), depending on caustic concentration. The potentialof overheating from steam or electrical tracing of causticequipment or piping to keep the caustic in solution should betaken into account when considering temperature factor.

The common remedial action is to stress relieve the fabricatedequipment to reduce residual stresses.



Figure 8 shows which conditions require PWHT of carbon steel toprevent caustic cracking.

4. 6 .4 Intergranular Corrosion and Cracking of Stainless Steels -Polythionic Acid Cracking

1. Sensitization

If austenitic SS is heated or cooled through thetemperature range of 700°F to 1500°F, the chromium alonggrain boundaries tends to combine with carbon to formchromium carbides. This process is called carbideprecipitation or sensitization.

Carbon diffuses towards the grain boundaries quite rapidlyin the sensitizing temperature range, but chromium is muchless mobile. As a result, all carbon in the alloy and onlythe chromium located in the areas adjacent to the grainboundaries are available for chromium carbide formation.The net effect is a depletion of chromium (which is thebasic reason for corrosion resistance of SS) and a drasticfall of corrosion resistance near grain boundaries.

Sensitization is a time dependent process. There is acomplex relationship between temperature and time tosensitization.

2. Sources of Sensitization

Sensitization may result from slow cooling during heattreatment and other fabricating processes (hot rolling,bending, etc.) or welding. Welding is probably the mainsource of austenitic SS sensitization. The problem in thiscase is aggravated by large size and complexity of weldedequipment and piping, which makes implementation of theprotective measures very difficult.

Normal welding procedures utilizing arc welding can inducesensitization. Generally, the higher the heat input duringwelding, the higher the probability of sensitization.

Sensitization from welding usually occurs in zones of thebase metal slightly away from the weld (heat affectedzones) rather than at the weld itself.

Sensitization can also result from operation in thesensitizing temperature range of 700°F to 1500°F.

3. Failure of Sensitized Stainless Steel

The depletion of the chromium content at grain boundariesof sensitized SS substantially decreases corrosionresistance of the grain boundaries. The metal becomessusceptible to rapid intergranular (along grain boundaries)failure. The intergranular attack rate is accelerated bygalvanic effect due to electrode potential differencebetween grains and boundary areas. Grain boundaries areanodic versus grain, and the area ratio is very unfavorable(large cathode - grain, small anode - grain boundary).

Damage rate on exposure of a sensitized SS to a corrosiveenvironment depends on severity of the environment andextent of sensitization. In sea water, a sensitized SSsheet may fail within weeks or months. In a boilingsolution containing CuSO45H2O (13 gm/l) and H2SO4 (47 mlconcentrated acid/l), which is used as an accelerated test



medium, failure occurs within hours. The intergranularcorrosion may also occur in comparatively mild media(dilute weak acids, both organic and inorganic, etc.).

Intergranular damage of sensitized SS can manifest inintergranular corrosion or (in presence of applied stressesor residual stresses in the metal) in intergranularcracking. In refinery applications, the most widespreadintergranular cracking of SS is polythionic acid cracking.Polythionic acids of the type H2SxO6 (where x varies from 3to 6) are formed by the reaction of oxygen and water withthe sulfide film that is present on SS surfaces as a resultof high temperature sulfidic corrosion. This crackingoccurs during shutdown periods when oxygen and water areavailable from steam or wash water used to removehydrocarbons before inspection or simply from atmosphericexposure.

4. Measures to Prevent Intergranular Corrosion

Three main methods are used to control or minimizeintergranular corrosion of austenitic SS.

a. Heat Treatment at 1920°F to 2000°F Followed byQuenching (Solution Anneal)

The high temperature treatment dissolves precipitatedcarbides in the austenitic matrix solid solution, andrapid cooling prevents their reformation. Thistreatment is recommended, for example, after weldingoperations. It is not always a feasible treatment,however, because of structure size and/or a tendency towarp during cooling.

b. Reduction of Carbon Content

This reduction does not allow sufficient carbide toform to cause intergranular attack. Alloys of lowcarbon content, e.g., < 0.03% C, are designated by theletter “L”, e.g., Types 304 L SS, 316 L SS. Thesealloys can be welded or otherwise heated in thesensitizing temperature range with much less resultantsusceptibility to intergranular corrosion. However,they are not immune and may sensitize after prolongedexposure in the sensitizing temperature range (700°F to1500°F).

c. Addition of Elements that Form Stable Carbides

These elements (Ti or Cb) have much greater affinityfor carbon than chromium and are added in sufficientamounts to combine with all of the free carbon in thesteel. Thus, carbides of the stabilizing elements formrather than chromium carbides. Alloys of this kind arecalled stabilized grades, e.g., Types 321, 347, 348 SS.They can be welded or otherwise heated within thesensitizing range without becoming susceptible tointergranular corrosion.

In welding operations, the weld rod usually contains Cbrather than Ti. Titanium tends to oxidize (burn out) atelevated temperature, with the danger of its residualconcentration becoming too low to stabilize the weldalloy against intergranular corrosion. Columbium, on



the other hand, is lost by oxidation to a lesserextent.

Unfortunately, even stabilized grades under certainconditions can undergo intergranular attack in a verynarrow zone immediately adjacent to the weld (calledknife-line attack). This knife-line attack is caused bydissolving all stabilizing elements carbides. Thedissolution results from high temperature and rapidcooling during welding. After this, the stabilizingelement carbides are no longer helpful. For bestresistance, heat treatment at 1600°F to 1650°F afterwelding (stabilizing anneal) is required toreprecipitate stabilizing element carbides.

Texaco guidelines for SS require use of low carbongrades for all welded items and stabilized grades forservices at temperatures of 700°F and higher.

Another method of protecting austenitic SS equipment fromintergranular cracking involves neutralizing the polythionicacids or other acid solutions (that may form during shutdownperiods) with soda ash wash. Suitable procedures to preventcracking are outlined in NACE document RP0170. These proceduresinclude nitrogen purging of components that were opened to theatmosphere, purging with dry air that has a dew point below-15°C (5°F), or neutralizing any acids that are formed bywashing components with a 2% aqueous soda ash (sodiumcarbonate) solution.

Soda ash solution can also be used for hydrotesting austeniticSS equipment prior to returning components to service. Residuesof soda ash solution should be left on components duringtemperature storage to prevent SCC.

High nickel alloys (especially those not containing stabilizingelements Cb and Ti, such as Incoloy 800 and Inconel 600) arealso susceptible to intergranular corrosion and cracking.Chemically stabilized alloys, such as Incoloy 825 and Inconel625, are much more resistant to sensitization.

To enhance corrosion resistance of Incoloy 825, Inco AlloyInternational recommends the following:

1. Final hot working should be done in a temperature range of1600°F - 1800°F.

2. Additional stabilizing annealing at 1725°F - 1800°F issuggested if the material is to be welded or subjected tofurther thermal treatment. Rapid cooling (forced air orwater quench) may be desired for heavier sections.

4. 6 .5 Chloride Stress Corrosion Cracking

Austenitic stainless steels are susceptible to stress corrosioncracking in waters and “wet” environments containing chlorides.Chloride SCC usually appears as transgranular, highly branchedcracks. In several cases, sensitized microstructures haveundergone intergranular cracking in chlorides.



The main factors contributing to chloride SCC include chlorideconcentration, temperature, pH, oxygen content, stress level,and susceptibility of steel.

1. Chloride Concentration

As a general rule, it may be accepted that the moreconcentrated the chloride, the more likely SCC becomes. Theconcentration of chloride ions capable of causing SCCdepends upon the condition of the other factors listedabove. At 10 ppm, the time to cracking in laboratory testsincreases so much that this concentration may be consideredsafe at most conditions which can be encountered in oilrefinery applications.

Stress corrosion cracking of austenitic stainless steels18-8 (such as 304L SS) at various chloride concentrationsis shown in Figure 10. It should be emphasized thatchloride concentration in water can increase because ofpartial water vaporization. Such vaporization can make aformerly safe solution unsafe. Therefore, it is recommendedthat any design of SS equipment which includesconcentrating mechanisms, such as wetting and drying cyclesand crevices, be avoided.

2. Temperature

Temperature is an important factor in chloride SCC. Itseldom occurs, except at elevated temperatures aboveapproximately 130°F.

Metal temperature, rather than process-side, water-in orwater-out temperatures, is important regarding chlorideSCC.

SS pump impellers in sea water service have shown nocracking problems despite the presence of chloride and highoxygen content. Cracking has occurred, however, at tropicallocations, where exposure to direct sunlight could increasemetal temperature above ambient.

3. pH

Acid chloride solutions are more often encountered when SCCoccurs. However, slightly alkaline solutions, too, cancause SCC, although it may require longer time and highertemperatures than in acid solutions. In alkaline solutions,the likelihood of chloride SCC is greatly reduced.

4. Oxygen Content

Oxygen appears to be necessary for chloride SCC in neutralsolutions, where oxygen reduction is the primary cathodicreaction in the corrosion portion of stress corrosioncracking. In acid chloride solutions, where hydrogenreduction is the primary cathodic reaction, SCC can occureven when the oxygen concentration is quite low. The oxygenconcentration in boiling magnesium chloride solution at311°F (which causes quick SCC of austenitic SS) has beendetermined to be just 0.3 ppm. Actually, oxygen is notnecessary for cracking in acidic solutions, such as MgCl2.On the other side, in neutral solutions, as oxygen contentincreases, fewer chlorides are necessary for SCC to occur.



This explains why, in some practical applications,stainless steel components, such as heat exchanger tubebundles, do not crack until removed from operation andexposed to air during shutdown.

5. Stress

Increasing the stress decreases the time before crackingoccurs. The minimum stress required to cause chloride SCCdepends on temperature, alloy composition, and environmentcomposition. In some cases, it has been observed to be aslow as approximately 10% of the yield stress. In othercases, cracking does not occur below the yield stresses.

From a practical standpoint, it can generally be assumedthat residual fabricating stresses, especially at welds,alone or in conjunction with normal operating stresses, aresufficient to cause chloride SCC in as-fabricated alloysthat are susceptible to chloride SCC. Even stress relievingheat treatments do not completely prevent chloride SCC.

6. Susceptibility of Alloys

The greatest susceptibility to chloride SCC is exhibited bySS with a nickel content of 8% (which is the nominalcomposition for 304 SS). Greater resistance is shown byalloys of either lower or higher nickel contents.

Four non-quantitative categories of relative susceptibilitymay be identified among austenitic SS:

a. Highest susceptibility - sulfur bearing 303 and 301and sensitized 304.

b. Intermediate susceptibility - nonsensitized 304, 304L.

c. Lower susceptibility - 316, 316L, 309.

d. Lowest susceptibility - 310, 314, 18Cr-18Ni-2Si(XM-15).

Alloys are classified as either resistant or immune tochloride SCC, depending on how they perform in acceleratedlaboratory tests. In general, an alloy is immune if itpasses the boiling 42% magnesium chloride test conducted inaccordance with ASTM G 36. Examples are Inconel 600,E-Brite (26Cr-1Mo), and commercially pure titanium. Theindustry has recognized the severity of this test. Somealloys that fail the G 36 test but pass less severelaboratory tests (e.g., boiling 25% sodium chloride), suchas Incoloy 800 and 825, austenitic-ferritic (duplex) SS2205 and 2507, and Carpenter 20Mo-6 (20Cr-35Ni-6Mo),typically provide many years of service in water-cooledheat exchangers.

Unfortunately, all of the immune and resistant alloys aremore expensive than traditional 300 series SS.

It is generally recognized that alloys with greater thanapproximately 40% nickel are immune to chloride SCC.

7. Mechanism

Modern corrosion theory considers the mechanism of chlorideSCC to be of an electrochemical-mechanical nature. Thecorrosion resistance of stainless steels is not based ontheir thermodynamic stability. It is caused by the



formation of surface thin passive oxide film, whichprotects the metal from further corrosion. Chlorides, beinghighly corrosive, cause partial damage of this passivefilm, which results in the formation of small pits on themetal surface. These pits act as a stress raiser. Thehighly stressed pit bottom becomes anodic in relation tothe rest of the surface that is covered with the film.These pits dissolve at a high rate and form a crack. Thecrack growth by metal dissolution continues until the crackreaches the critical size. It then starts to propagate byfracture mechanics mechanism. Eventually mechanical failureoccurs.

The above mechanism of a strongly localized processexplains why chloride SCC occurs without any appreciablegeneral corrosion.

8. Main Sources of Chlorides in Refineries

a. Chloride salts from crude oil, produced water, andballast water.

b. Water condensed from process stream (process water).

c. Cooling water, wash-up water, and fire water.

d. Boiler feedwater and stripping system.

e. Catalyst.

f. Residue from hydrotest water and other manufacturingoperations.

g. Hydrogen that is used in hydrotreating andhydrocracking processes may form hydrogen chloride,for example, by reacting with chlorides in oil,catalyst, reactor refractory lining, amine solutioncarryover, etc. Ammonia, which also may be present inthe process stream, can react with hydrogen chlorideand form ammonium chloride. The latter at temperatureslower than 400°F to 450°F forms deposits and leaves asource of chlorides on the metal surface. Bothhydrogen chloride and ammonium chloride, whendissolved in condensed water, will form acid chloridesolutions (NH4Cl is an acid salt due to hydrolysis)which are very aggressive from an SCC standpoint.

h. Insulation may also be the chloride source and causethe retention of water and chloride concentratingunder insulation.

Chloride SCC may occur during service or down periods,depending on the time chloride containing solutions arepresent in the process equipment. It may start not onlyon the inside surface but also on the outside metalsurface (for example, by wash-up water, fire water,atmospheric precipitations, or under insulation).

In one case, chloride SCC was caused by seawater spraycarried by prevailing winds. The spray soaked theinsulation over 304 SS line, chlorides wereconcentrated by evaporation, and cracking occurred inthe areas with residual weld stresses. Other cases ofcracking under insulation have resulted from waterdripping on insulated pipe and leaching chlorides frominsulation.



9. Measures to Prevent Chloride SCC

a. Use of resistant alloys. Ferritic SS, such as 405(12Cr), 430 (17Cr), and E-Brite (26Cr-1Mo), are notsusceptible to chloride SCC and can be used instead ofaustenitic SS, if allowed by their corrosionresistance and mechanical properties. Duplex SS (2205and 2507) also have high resistance to cracking.

Higher alloy materials (Inconel, Incoloy, Carpenter20Cb-3, etc.) can be used. In practice, SS and nickelalloys containing greater than 30% Ni are immune tochloride SCC in most refinery environments.

b. Use of austenitic SS as an internal cladding ratherthan as a base metal. Cracking would be arrested onthe interface between the cladding and base metal.

c. If possible, use of carbon steel with a heavycorrosion allowance instead of SS.

d. In SS equipment and piping design, avoidance of gapsand crevices where water solution can be trapped,concentrate in chloride, and cause cracking (e.g., useof butt full penetration welds instead of socketweld). If possible, holes should be used to drainsmall closed voids.

e. Minimization of the amount of water and oxygen thatenters the system under all circumstances (washing,shut down, operations, etc.). If some water cominginto the system is unavoidable, the chloride contentshould not exceed 10 ppm. The oxygen content in thewater should be kept to a minimum by blanketing withnon-oxygen gas, such as nitrogen with the addition ofammonia. Each time after water enters the system, itshould be drained thoroughly during start up byflushing with dry kerosene or equal.

An alternative to low chloride water is an aqueous 0.5%sodium nitrate solution, recommended by NACE StandardRP-01-70 as a chloride cracking inhibitor for SS.Caution: excess NaNO3 can cause SCC of carbon steel.

Ammonia should be added to nitrogen, steam, or anyother gas used during start-up and shutdown. Ammoniashould be added in the concentration to ensure that anycondensate has a pH of 9 or above.

f. The following measures are recommended to preventchloride SCC under insulation:

(1) Using insulation that conforms to ASTM C 795,“Specification for Thermal Insulation for Use inContact with Austenitic Stainless Steel”.

(2) Protective coating of the vessel or pipingbefore insulation (epoxy, silicon-base coating,etc.).

(3) Installation of aluminum foil under insulation.This method is claimed to provide both aphysical barrier to chloride migration to SSsurface, as well as sacrificial cathodicprotection to SS if the insulation becomes wet.



(4) Installation of electric or steam heat tracingsystems to maintain the external SS surfacetemperature at a higher level than the water dewpoint to prevent water condensation underinsulation.

4. 6 .6 Amine Cracking

Carbon steel is susceptible to SCC in rich and lean aminesolutions. Cracking in fresh, uncontaminated amine solutionshas not been observed so far.

Amine cracking appears to be similar in many ways to alkalinecracking. Cracks are intergranular and form in places whereprotective film of corrosion products break. Cracking is notrelated to weld hardness.

The common remedial action is to stress relieve all of thefabricated equipment and piping regardless of servicetemperature.

4. 6 .7 Ammonia Cracking

Ammonia cracking in refineries is typically seen in copperalloy heat exchange tubing.

Admiralty and aluminum brass are very susceptible to crackingwhen stressed and exposed to aqueous environments containingammonia or ammonium compounds especially in the presence ofair. The common remedial action is to specify 70-30 Cu-Ni,which is more resistant to cracking. Water wash is recommendedfor brass condenser tubes before exposure to air to wash outdeposits containing ammonium compounds.

Monel corrodes rapidly in high pH ammonia environments. In someisolated cases, it has cracked when highly stressed in sourwater with ammonia present.

Carbon and alloy steels are subject to cracking in contact withanhydrous liquid ammonia at room temperature. Cracking isavoided by stress relieved heat treatment and/or by addition of0.2% water, which acts as an inhibitor.

4.7 Scaling Resistance

The following table shows the maximum temperatures in atmospheres ofair, steam, or flue gas at which the various alloys withstand excessivescaling. These temperatures should be considered approximate and maychange significantly, depending on the specific atmosphere.

MAX. TEMP. w/oMATERIAL EXCESSIVE SCALING (°F)

Carbon Steel 10002.25Cr-1Mo 11005Cr-0.5Mo 11509Cr-1Mo 1200SS Type 410 1300SS Type 304, 316, 321, 347 1600SS Type 310 (25Cr-20Ni) 1900



4.8 Fuel Ash Corrosion

Fuel ash corrosion is a potential problem in heaters and boilers ifburning high sulfur (approximately 2% plus) fuel oil with 50 ppm or morevanadium. The sulfates and vanadates formed during combustion combineand become liquid compounds in the 1150°F to 1300°F range. The liquid isvery corrosive and will attack heater and boiler parts that are normallyscaling resistant. Current solutions to the fuel ash problem include:

1. Limiting maximum tube wall temperature to 1200°F based on practicalexperiences.

2. Adding magnesium and aluminum oxides to the fuel oil. Thesematerials raise the melting point of the sulfate - vanadatecompounds so they do not liquefy.

3. Using special alloys, such as 50Cr-50Ni. The 50Cr-50Ni alloy maygive several times the service life than that expected for standardheater and boiler alloys.

4. Certain refractory coatings have been reasonably successful.

4.9 Elevated Temperature Strength

For comparison purposes, the 100,000 hour stress to rupture versustemperature curves for several commonly used alloys are shown in Figure11. Elevated temperature strength as stress to rupture and percent creepin 100,000 hours determine the allowable stress for recognized codes,such as ASME, if operating in the creep range (above 800°F).

API 530, “Recommended Practice for Calculation of Heater Tube Thicknessin Petroleum Refineries”, specifies the following limits for designmetal temperatures for different alloys.

MATERIALMAXIMUM DESIGNMETAL TEMP. (°F)

Carbon Steel 1000

Carbon Steel - 0.5Mo 1100

1.25Cr-0.5Mo 1100

2.25Cr-1Mo 1200

3Cr-1Mo 1200

5Cr-0.5Mo 1200

5Cr-0.5Mo-1.5Si 1300

7Cr-0.5Mo 1300

9Cr-1Mo 1300

SS 304, 304H, 316, 316H, 321, 321H, 347, 347H 1500

Incoloy 800H 1800

HK-40 (Cast Fe-25Cr-21Ni-0.5Mo, ASTM A 608 GR HK 40) 1850

4.10 High Temperature Microstructural or Chemical Changes and Embrittlement

Elevated temperature exposure causes metallurgical changes to occur inmany of the metals and alloys used in refinery service. Many of themicrostructural changes are time and temperature dependent. Some arereversible. The possibility of microstructural changes that may resultin embrittlement, decreased strength, or notch toughness must beconsidered when selecting materials.



4. 10 .1 Hardening and Softening

Hardening of steels is the result of martensite formation afterheating to above the lower critical temperature (1340°F forcarbon steel) followed by rapid cooling. A brittle martensiticcarbide structure is formed that is not desirable for refineryequipment and piping. Hardening can occur in the course ofwelding fabrication or if steels are exposed to severeoverheating, such as in a fire. Hot bending can also be asource of hardening.

Welding of carbon steels with less than 0.25% carbon generallypresents no hardening problems, because the usual cooling ratesare not fast enough to permit martensitic formation. However,carbon steel with more than 0.35% carbon, low alloy steels, andmartensitic straight chromium stainless steels will hardensimply by air cooling after welding. Similarly, during fireexposure, these hardenable materials can become extremely hardand brittle to the extent that they are not serviceable.

To prevent cracking of hardened metal after welding, preheattreatment and postweld heat treatments are used. In the case offire damaged material, hardness surveys using portable testerscan be used to identify equipment and piping hardened byoverheating and quenching.

Conversely, softening can also be a problem with refineryequipment. Some pressure vessels are made of low alloy steelsthat are quench and tempered or normalized and tempered tooptimize design strength. Subsequent welding, heating forbending, or exposure to fire can degrade strength propertiessuch that replacement or reheat treatment will be required.Commonly used bolting, ASTM A 193 Grade B7, is an example of anintentionally hardened component. Hydroprocessing thickwallreactors made of 2.25Cr-1Mo material are another example.

4. 10 .2 Grain Growth

Grain growth occurs if steels are heated above a certaintemperature, beginning at approximately 1100°F for carbonsteel. It is most pronounced at 1350°F. The amount of growthdepends on the maximum temperature reached and the length oftime at temperature. Austenitic stainless steels and highnickel-chromium alloys do not become subject to grain growthuntil heated to above 1650°F.

Grain growth lowers the room temperature tensile strength andnotch toughness but increases both creep strength and rupturestrength. In practice, grain growth has not been a significantfactor in refinery failures. It is, however, very useful forpinpointing furnace operational problems that have led tolocalized overheating failures of furnace tubes. Metallographicexamination of the microstructure of failed components canreveal, through grain growth, the temperature to which thecomponent was exposed. This technique is also applied torefinery fire damage evaluations.

4. 10 .3 Graphitization

Graphitization problems can occur with carbon and carbon -0.5Mo steels operating above approximately 850°F.



Graphitization represents decomposition of the iron carbidephase into iron and graphite.

If the graphite particles form a continuous line through thethickness of a pressure part, the load carrying ability of thepart may be seriously decreased. The stress rupture strength isalso drastically reduced.

Weld heat affected zones usually tend to have moregraphitization problems.

Some carbon steels are more susceptible to graphitization thanothers. Carbon - 0.5Mo can be very susceptible.

Steels with chromium added form stable enough carbides thatresist the graphitization.

4. 10 .4 Temper Embrittlement and 885°F Embrittlement

Temper embrittlement is a microstructural change that occurswith time between approximately 700°F and 1000°F. Roomtemperature notch toughness drops very significantly. Ithappens most often in low alloy chrome-moly steels.

The embrittlement is easily identified by its effect on thebrittle-to-ductile failure transition temperature in impacttests, such as the Charpy V-notch test. In extreme cases, asteel that starts out with a transition temperature of -120°Fcan, after long exposure to temperatures in the embrittlingrange, have a transition temperature as high as 420°F. Thismeans that, even though the steel is fully ductile at itsoperating temperature, as the temperature is lowered duringshutdown, it quickly passes into the brittle range. An existingcrack or defect could then propagate and cause failure eitherwith or without an impact load.

The embrittlement mechanism includes segregation of theresponsible impurities along prior austenitic grain boundaries.

Temper embrittlement of older equipment is handled by limitingpressurization until the equipment temperature is well abovethe transition temperature. Temper embrittlement is alsoreversible. Steel can be deembrittled by heating to above1100°F to 1200°F, followed by rapid cooling to roomtemperature. This is not practical for large pressure vesselsin refinery conditions. Of course, embrittlement will return ifexposure in the embrittlement range again occurs. Thesusceptibility of new equipment to temper embrittlement can nowbe controlled by alloy composition to reduce the content ofembrittling impurities. (For more detail, see Section 5.3.)

885°F embrittlement occurs after aging of ferritic stainlesssteels above 12Cr at 700°F to 1000°F and produces a loss ofambient temperature ductility. This loss of ductility isunrelated to sigma embrittlement. Ductility can be restored byheating to 1200°F, followed by rapid cooling.



4. 10 .5 Sigma Phase

Sigma phase formation occurs when austenitic and otherstainless steels with more than 17% chromium are held in thetemperature range of 1100°F to 1700°F for an extended period oftime that depends on temperature. Sigma is a hard, brittle,non-magnetic phase containing approximately 50% Cr. Chemically,sigma phase represents an iron-chromium intermetallic compoundapproximately equivalent to FeCr. In austenitic SS, it formsfrom residual ferrite. Cold work promotes its formation. Thereis an increase in the alloy's room temperature tensile strengthand hardness, accompanied by a decrease in ductility to thepoint of brittleness. As a result, cracking is likely to occurduring cooling from operating temperatures, handling, andrepair welding.

Appreciable amounts of sigma phase can also interfere with weldrepairs on a component.

Nickel promotes the formation of austenite, and chromiumpromotes the ferrite phase. Therefore, high nickel alloys areimmune to sigma formation, and the high chromium alloys aresusceptible. The susceptibility and rate of formation of sigmaphase in intermediate alloys depend on the ratio of Ni and Cr.During sigma transformation, neighboring areas are depleted ofchromium. This can lead to failures along grain boundaries ifthe material is exposed to corrosive conditions.

Sigma is most likely to be found in cast furnace tubes andother cast furnace components. HK cast stainless steelcontaining 25% Cr and 20% Ni is especially susceptible to sigmaphase formation. Heating the embrittled component to between1800°F and 2000°F results in dissolving the sigma phase intothe austenite matrix and restoring ambient temperatureductility. A more practical means of avoiding sigma is to limitthe ferrite content of the stainless steel. To avoid sigmaphase embrittlement, an austenitic stainless steel should nothave a ferrite content greater than 10%.

Austenitic stainless steel welds and corrosion resistant weldoverlays may form significant amounts of sigma duringfabrication. The austenitic weld deposit problems can also beminimized by limiting ferrite content to a maximum of 10%.

4. 10 .6 Carburization and Decarburization

Carburization is the increase of carbon content in the surfacelayer of the steel and results from carbon diffusion into themetal during heating in a suitable carbonaceous atmosphere(hydrocarbons, e.g., methane or carbon monoxide). Carburizationoccurs at temperatures above 1000°F. The reverse process,decarburization, can occur in elevated temperature hydrogen(described in Section 4.2) or carbon dioxide. Frequentlyencountered mixtures of carbon monoxide and carbon dioxide arecapable of both carburizing and decarburizing depending ontemperature, the ratio of carbon monoxide to carbon dioxide,and the carbon content of the steel.

Coke deposits on furnace tubes are the usual source of carbon.Iron sulfide scale is believed to act as a catalyst in thecarburization process. Carburization depends on the rate of



diffusion of elemental carbon into the metal and increasesrapidly with increasing temperature. The increase in carboncontent results in an increase in the hardening tendency offerritic steels. When carburized steel is cooled, a brittlestructure can result. The presence of such a hard, brittlestructure may result in spalling or cracking.

The use of low - carbon grades of stainless steel to preventsensitization to intergranular corrosion will be of littlevalue if substantial carburization occurs before the alloy isexposed to the conditions causing sensitization and corrosion.

Resistance to carburization escalates with increasing chromiumcontent in steel. Decarburization may decrease the endurancelimit of steel.

4. 10 .7 Liquid Metal Embrittlement

Liquid metal embrittlement is a form of catastrophic brittlefailure of a normally ductile metal caused when in contact witha liquid metal and stressed in tension. In refineries, liquidmetal embrittlement has been experienced in copper alloysexposed to mercury and austenitic stainless steels in contactwith molten zinc or aluminum.

Mercury that is present in some crude oils and subsequentrefinery distillation processes can condense and concentrate atlow spots in equipment, such as condenser shells. Similarly,the failure of process instruments that use mercury has beenknown to introduce the liquid metal into refinery streams.Copper alloys, such as used for condenser tubes, when contactedby mercury, are wetted intergranularly and then fracture underrelatively low tensile loads.

Welding and fire exposure can produce embrittlement from moltenzinc from galvanized components and molten aluminum frominsulation coverings that are in close contact with austeniticstainless steels. Wetting of the austenitic steel grainboundaries by the zinc or aluminum results in a bond strengthreduction and in intergranular cracking.

In the case of zinc-rich paints, only those that have metalliczinc powder as a principal component can cause zincembrittlement of austenitic stainless steels. Paints containingzinc oxide or zinc chromates do not cause cracking.

4.11 References

1. API Publication 941, “Steels for Hydrogen Service at ElevatedTemperatures and Pressures in Petroleum Refineries andPetrochemical Plants”.

2. “High Temperature Sulfidic Corrosion in Hydrogen Free Environment”,Henry F. McConomy, API 28th Mid-year Meeting, May 1963.

3. “New Computer Correlations to Estimate Corrosion of Steels byRefinery Streams Containing Hydrogen Sulfide”, A.S. Couper and J.W.Gorman. NACE, March 1970.

4. NACE, “Corrosion Data Survey”, 1985.



5. “Corrosion in Petroleum Refining and Petrochemical Operations”,J.Gudzeit, R.D. Merrick, L.R. Scharfstein, ASM Metals Handbook,Ninth Edition, Volume 13, “Corrosion”, 1987.

6. “An Exploratory Examination of the Effect of SOHIC Damage on theFracture Resistance of Carbon Steels”, M.S. Cayard, et al.,Corrosion 97, Paper 525.

7. “Fabrication, Welding and Heat Treatment of Nickel Alloys UNSN08800, N08810, N08811 and N08825”, C.S. Tassen et al., Corrosion96, Paper 601.

5. MATERIALS FOR PROCESS UNITS

5.1 General

Selection of materials described in this section should be consideredtypical and most frequently used rather than exact. Different materialsmay be required, depending on the particular process conditions.

5.2 Crude Distilling Unit

5. 2 .1 General

Crude oil, as such, is not corrosive to carbon steel. Corrosionproblems are created by the following impurities: inorganicsalts, sulfur compounds, organic acids (mainly naphthenicacid), and organic chlorides.

1. Inorganic Salts

Inorganic salts are present in brine produced with thecrude oil or are picked up as a contaminant from tankerballast. The bulk of the salts present in water are sodiumchloride (NaCl), magnesium chloride (MgCl2), and calciumchloride (CaCl2), commonly reflecting the composition ofseawater.

When crude oil is preheated prior to processing, both MgCl2and CaCl2 begin to hydrolyze at approximately 250°F andabove and form hydrogen chloride HCl. The chemical reactionof high temperature hydrolysis is:

MgCl2 + H2O → 2HCl + MgO or HCl + MgOH - depending ontemperature

The same is true for CaCl2. NaCl does not hydrolyze to anyappreciable extent.

HCl vapor thus formed is not corrosive at temperaturesabove the water dew point. For this reason, there is nocorrosive acid attack in the preheat system where no freewater is present. In the preflash and atmospheric column,HCl is carried up the column with the hydrocarbon where,being highly water soluble, it dissolves in the condensingwater to form hydrochloric acid. This highly corrosive acidcan create severe corrosion problems in the top of thecolumn, the overhead line, the overhead exchanger, andcondensers. The source of the condensing water can be thecrude oil, stripping steam, or desalters. The resultingcorrosion reaction with steel is:

Fe + 2HCl = FeCl2 + H2The presence of H2S causes another reaction as follows:



FeCl2 + H2S = 2HCl + FeS

The formation of HCl thus perpetuates the cycle.

Several steps can be taken to reduce the severity of thisacid attack on carbon steel:

a. Desalting.

b. Caustic addition.

c. Overhead pH control.

d. Use of corrosion inhibitors.

e. Water washing.

The primary purpose of a desalter is to reduce the amountof salt in the crude oil. The targeted level is less than1 lb/1000 bbl (PTB). In addition to salt removal, thedesalting process also removes entrained solids, such assand, salt, rust, and paraffin wax crystals which may bepresent in the crude. In addition to decreasing theseverity of the overhead corrosion problems, the desaltingprocess also decreases plugging and fouling in heaters andheat exchangers.

The addition of small amounts of dilute (3% weight) caustic(NaOH) to the desalted crude is often an effective way toreduce the amount of HCl hydrolyzing in the preheaters. Thecaustic converts the hydrolyzable MgCl2 and CaCl2 to thenon-hydrolyzable NaCl, thus reducing the amount of HClproduced. While the results of caustic addition can bequite beneficial, there is a risk of plugging, metalcracking, and catalyst contamination problems in downstreamunits if it is not controlled properly. The causticconcentration in the crude oil should not exceed 3 PTB or10 wppm.

The desired result of an overhead pH control program is toproduce an essentially noncorrosive environment byneutralizing the acidic components in the overhead liquid.This is done by injecting ammonia, an organic neutralizingamine, or a combination of the two. The desired pH controlrange depends on the concentrations of the variouscomponents of the corrosive environment (usually between 5and 6).

Most overhead corrosion control programs include injectionof a film forming organic inhibitor as an additionalprotection. These inhibitors establish a continuouslyreplenished thin film which forms a protective barrier forthe metal surface underneath. For maximum results, properpH control of the system is essential.

When fouling with neutralization reaction products becomesa problem, water should be injected, either intermittentlyor continuously, to dissolve salt deposits.

2. Sulfur Compounds

It is difficult to exactly predict the corrosivity of acrude oil based entirely on its sulfur content. Generally,the dividing line between non-corrosive and corrosive is atapproximately 0.5% to 0.6% level. The more precise factoris not the total amount of sulfur compounds but rather the



extent to which these compounds thermally decompose to formH2S, the most corrosive sulfur compound.

High temperature sulfur attack is a serious problem in hotportions of the atmospheric column, preflash column, vacuumcolumn, fired heater tubes, hot heat exchangers, andassociated piping. The problem is alleviated by the use ofproper alloy materials, which will be discussed later.

The aqueous phase H2S corrosion and cracking is widespreadin predominantly carbon steel equipment. This service mayrequire PWHT and use of HIC resistant steels (see 4.6.2).

3. Organic Acids

Many crude oils contain organic acids but seldom do theyconstitute a serious corrosion problem. Some crudes containsufficient quantities of naphthenic acid (one of theorganic acids) to cause severe problems in those parts ofthe crude unit operating over 450°F. Thus, naphthenic acidattack may occur in the same places as high temperaturesulfur attack, such as heater tube outlets, transfer lines,column flash zones, and pumps. The corrosion rate isstrongly affected by velocity. The most commonly usedmaterial is Type 316 stainless steel which performs wellbecause of its molybdenum content. For better protection,Mo content in 316 stainless steel should be no less than2.5%.

4. Organic Chlorides

Organic chlorides constitute a contaminant in crude oil,often resulting from the carryover of chlorinated solventswhich are used in the oil fields. They can also be pickedup by the crude during transportation in contaminated tanksor lines. Since organic chlorides are not removed by thedesalters, they can decompose in the heaters and causeerratic pH control and accelerated corrosion in the crudeunit overhead systems, as well as downstream units.

5. 2 .2 Material Selection

1. Atmospheric Towers - Carbon Steel Base Metal (From Top ofTower Down)

a. Monel clad past dew point, below top reflux but notbelow 400°F (usually 2 - 3 trays) if substantialhydrochloric acid corrosion is expected.

b. 316L clad 450°F down (for naphthenic acid protection).

c. 410S clad 500°F down (without naphthenic acid).

d. Transition from Monel to stainless clad should be 0.25inch corrosion allowance carbon steel.

e. Trays same as clad. Trays in carbon steel sectionshould be 410S.

2. Vacuum Tower - Carbon Steel Base Metal (From Top of TowerDown)

a. 0.25 inch corrosion allowance to 450°F-500°F (withoutnaphthenic acid).

b. 316L clad from 450°F down (for naphthenic acidprotection).



c. 410S clad from 500°F down (without naphthenic acid).

d. Trays match clad (410S trays in carbon steel section).

3. Stripper Towers

Stripper towers should be similar to atmospheric tower.

4. Other Towers

Carbon steel with 0.125 inch corrosion allowance, unlessestimated corrosion rate exceeds 10 mils per year, such asin hot or aqueous sulfide. If there is a question, specify0.25 inch corrosion allowance if alloy clad not justified.

5. Drums

Consistent with towers. Gunite lining used where aqueoussulfide considered to be a problem. Monel liners in boot ornozzles are usually used if too small to gunite.

6. Exchangers

a. Tubes

(1) Carbon steel to 500°F.

(2) 5Cr-0.5Mo from 500°F to 650°F.

(3) 9Cr or 12Cr above 650°F.

b. Tubesheets, Shell, and Channels

(1) Carbon steel to 550°F, with 0.25 inch corrosionallowance above 500°F or where there isconsiderable aqueous sulfide.

(2) 410S clad above 550°F.

c. Baffles

(1) Baffles should match shell.

(2) If shell has high corrosion allowance, bafflesshould also have high corrosion allowance.

7. Overhead Condensing System

a. Air Cooler - Carbon steel for tubes, tubesheets, andheaders normally with 0.25 inch corrosion allowance(except tubes).

Where considerable hydrochloric acid and/or aqueoussulfide are present, use Monel or Monel lined headersand tubesheets with Monel or 70-30 Cu-Ni tubes.Alternate material for tube: Titanium Grade 2.

b. Condensers and Coolers - cooled by fresh water(cooling water in tube side).

(1) Tubes - admiralty or 70-30 Cu-Ni if ammoniastress corrosion cracking potential high (e.g.,pH greater than 7 in presence of ammonia).

(2) Tubesheets - naval brass or Monel lined carbonsteel, or carbon steel with heavy corrosionallowance.

(3) Channels and floating heads - Monel lined carbonsteel or carbon steel with heavy corrosionallowance.



c. Condensers and Coolers - cooled by seawater (coolingwater in tube side).

(1) Tubes - aluminum brass or 70-30 Cu-Ni orTitanium Grade 2 if ammonia stress corrosioncracking potential is high.

(2) Tubesheets - naval brass or aluminum bronze orMonel lined carbon steel.

(3) Channels and floating heads - aluminum bronze or0.25 inch corrosion allowance carbon steel withan epoxy phenolic coating and galvanic anodes.

General Note: Alternate materials for tubes are Moneland 904 SS. Carbon steel can be used only when there isvery careful cooling water control.

8. Heater Tubes

a. Atmospheric.

(1) Convection - usually 5Cr-0.5Mo.

(2) Radiant - 5Cr-0.5Mo or 9Cr-1Mo with 0.125 inchcorrosion allowance.

(3) Steam superheaters - dependent on flue gastemperature. At temperatures above 850°F, tubesshould be 1.25Cr-0.5Mo tubes. Below 850°F, tubesshould be carbon steel.

b. Vacuum.

(1) Convection - usually 9Cr-1Mo.

(2) Radiant - 9Cr-1Mo with 0.125 inch corrosionallowance.

(3) Steam superheater - dependent on flue gastemperature. At temperature above 850°F, tubesshould be 1.25Cr-0.5Mo. Below 850°F, tubesshould be carbon steel.

c. Other heaters - other heaters are normally carbonsteel with 0.125 inch corrosion allowance.

d. General, all heaters - Take potential fuel ashcorrosion problems into account when designing fueloil fired heaters. As a guide, begin to anticipatepotential problems on hangers, supports, and baffleswith sulfur greater than 2% and vanadium greater than50 ppm. For remedies, see Section 4.8.

9. Piping

a. Process Piping - Usual Materials Selection

(1) Carbon steel to 550°F. Corrosion allowance above500°F and where considerable aqueous sulfide ispresent should be 0.25 inch.

(2) 5Cr-0.5Mo from 550°F to 650°F.

(3) 9Cr-1Mo above 650°F.

b. Sour water piping - Past practice has been to usecement lined pipe with small Monel pipe and Moneltrimmed carbon steel valves. Carbon steel with 3/16inch corrosion allowance and 316 SS valve trim has



been used quite successfully and is much moreeconomical. GEMS J-2D, Table 7, contains availablepiping material service specifications.

c. Atmospheric overhead line - line should be kept abovethe dew point to permit use of 3/16 inch corrosionallowance carbon steel. Monel can be used after theoverhead stream is condensed.

d. Heater transfer lines - atmospheric and vacuum heatertransfer lines are usually 9Cr-1Mo unless naphthenicacid is expected to be a problem. Consideration shouldbe given to the use of 316L or 317L if highneutralization number crudes are to be run.

e. Seawater Line

(1) Large lines - cement lined steel.

(2) Small lines - Monel, plastic (high densitypolyethelene or equal), or other nonmetallicmaterials.

10. Pumps

In general, impellers should be cast iron or carbon steelwith steel cases. Above 550°F cases and impellers should be12Cr or CA6NM (cast 12Cr). Use of cast iron or ductile castiron should be considered for noncorrosive water services.

Seawater pumps should be Ni-resist (ductile austenitic castiron) or Monel for wetted shafts.

5.3 Hydrotreater - Hydrocracker

5. 3 .1 General

The corrosion problems which should be taken into considerationfor hydroprocessing units include high temperature sulfidation,high temperature hydrogen attack, hydrogen cracking, chloridecracking, polythionic acid cracking, aqueous sulfide corrosion,and ammonium hydrosulfide corrosion.

Materials for high temperature hydrogen are selected based onNelson Curves (Figure 1). Based on the recent experience, theCr content in 1Cr-0.5Mo and 1.25Cr-0.5Mo steels in hightemperature hydrogen should be no less than 1.25% to avoidhydrogen attack problems.

When temperature exceeds 500°F-550°F in H2-H2S mixtures, severecorrosion occurs on carbon and low-alloy steels. Beforehydrogen enters the process stream, 5Cr-0.5Mo or 9Cr-1Mo can beused. Downstream of the hydrogen injection, 300 seriesstainless steels are required. Low chrome steels in theseconditions require aluminizing to minimize high temperaturesulfidation (rapid attack can still occur at breaks in thecoating).

5. 3 .2 Reactors

1. Materials selection for reactors is based on:

a. Resistance to hydrogen attack.

b. Resistance to H2 - H2S corrosion.

c. Notch toughness considerations.



d. Strength and fabrication considerations.

Most hydrotreater and hydrocracker reactors are hot shellvessels. The minimum base material for a reactor isdetermined based on the resistance to hydrogen attack atthe process hydrogen partial pressure and temperature.Minimum base materials usually range from 1.25Cr-0.5Mo to2.25Cr-1Mo.

The need for higher alloy corrosion protection by usingclad or weld overlay can be estimated by using the Coupercurves for H2 - H2S corrosion. (See Figures 4 through 6) Inmost hydrotreater reactor applications, Type 321 SS clad orType 347 SS weld overlay is required. The choice of usingclad or overlay is usually up to the fabricator. Clad isusually used up to approximately 2.50 inch base metalthickness and overlay above. The decision is made by thefabricator depending on his overlay facilities and theproblem of obtaining clad in heavy sections.

The notch toughness and fabrication considerations dependon the size and thickness of the reactor. For example, itis often desirable to minimize weight and increase notchtoughness by using 2.25Cr-1Mo with a Division 2 design.These considerations usually apply above 2.50 - 3.0 inchthickness.

During high temperature service, the reactor base metal mayundergo temper embrittlement (see Section 4.10.4) which maycause substantial decrease of notch toughness. To reducesusceptibility and to control temper embrittlement of2.25Cr-1Mo, the following requirements shall be satisfied.

2. Chemical Limits Requirement

a. Reactor plate and forging material chemical limitsshall be controlled as follows:

J = (Si + Mn) x (P + Sn) x 104 < 100 (with the elementsin weight percent)

Consideration should be given in relation to theminimum silicon level content to ensure that hottensile properties are not detrimentally reduced by lowsilicon content.

b. Tramp elements shall be as follows:

P = 0.010% MAX

Sn = 0.010% MAX

Sb = 0.004% MAX

As = 0.015% MAX

S = 0.010% MAX

Cu = 0.200% MAX

Ni = 0.200% MAX

V = 0.050% MAX

P + S = 0.018% MAX

c. Weld metal chemical composition should be controlledwithin the following limits:



x = 10P + 5Sb + 4Sn + As

100 15≤

(With the elements in weight PPM.)

3. Additional Notch Toughness Requirement

a. Samples representing base metal, weld metal, and heataffected zone should be additionally impact testedafter step cooling treatment per the following cycle:

(1) Hold at 1100°F for 1 hour.

(2) Cool 10°F/hr to 1000°F and hold for 15 hours.




(6) Cool 50°F/hr to 600°F.

(7) Air cool.

b. The following 40 ft-lb impact energy transitionrelationship should be maintained after a step coolingtreatment:

T + 3 T To min∆ ≤

Where:

To = Temperature at which Charpy V-notchtoughness is 40 ft-lb after PWHT andbefore step cooling.

∆T = Tsc - To (or temperature shift).

Tsc = Temperature at which Charpy V-notchtoughness is 40 ft-lb after PWHT plus stepcooling.

Tmin = Minimum metal design temperature.

Reactors are designed to ASME Section VIII, Division 1or Division 2. Division 2 permits higher allowablestresses but specifies more rigorous inspection andstress analysis.

4. Hydrogen Embrittlement

Hydrogen embrittlement is also a concern in the reactors ofhydroprocessing units. Such reactors operate at high enoughtemperatures and hydrogen partial pressures to result in asignificant concentration of dissolved hydrogen within thewalls at operating temperatures. If the reactor walls arethick enough and are cooled rapidly when shutting down, thedissolved hydrogen will not be able to escape from themetal during cooling. The entrapped hydrogen may adverselyaffect metal mechanical properties and fracture mechanicsproperties, especially at temperatures above 300°F (149°C).One concern is that preexisting fabrication flaws or otherdefects will grow due to hydrogen embrittlement.

To avoid this risk, a shutdown procedure may be required tolet a significant amount of hydrogen diffuse out of themetal before the reactor is cooled below 300°F. Thisprocedure includes an outgassing step that involves holding



at high temperatures and low hydrogen partial pressures forparticular periods of time as part of the cooling process.

Thick-walled reactors in hydrogen service should beinspected with particular care after initial constructionand during plant turnarounds to guard against existingdefects which might enlarge due to hydrogen embrittlement.

5. Test Blocks

Texaco practice for a number of years has been to installtest blocks in hydroprocessing reactors (usually two perreactor). Test blocks should be made of the same heats asthe reactor materials and should be welded using the sameproduction welding materials and the same weldingprocedures and NDE methods as for the reactors.

If the reactor has an SS weld overlay, the test blocksshould be overlaid on all sides with the same overlay.

Test blocks are recommended to be installed in the gasphase with the highest temperature.

Testing test blocks during reactor operation will determineif the metal has undergone any deterioration. The followingtests are usually performed: tensile and impact tests, stepcooling tests, and metallography.

5. 3 .3 Exchangers

As a minimum, all exchange equipment that will handle hydrogenshould be satisfactory for the process design hydrogen partialpressure and temperature. Materials are also selected on thebasis of the estimated corrosion rate from the H2S or H2 - H2Scurves. Corrosion rates on the feed side of the reactors shouldbe kept very low to minimize scaling and subsequent reactorpressure drop problems. Heat exchange may be limited on thefeed side due to fouling. Antifoulants should be considered ifthe feed from tankage is used. Tankage feed may containconsiderable oxygen that may form long chain polymers onheating.

Feed-effluent exchangers are made of materials similar to thoseused in reactors. Tubes are usually 321 or 347 SS.

Materials for exchangers not handling hydrogen are selected onthe basis of sulfur corrosion curves and experience. Thematerials temperature breaks are similar to the crude unit aslong as hydrogen is not involved.

5. 3 .4 Condensers and Coolers

Reactor section condensers and coolers are usually carbon steelwith a heavy corrosion allowance. The brasses normally used inwater service are very vulnerable to the high ammoniaconcentration. Waterside corrosion problems can be expected,particularly on the reactor effluent coolers, which usuallyhave the cooling water on the shell side. Cooling watervelocities that are too low promote serious pitting problems.

Most other condensers and coolers can be the same as specifiedin the crude unit, unless special problems exist.



5. 3 .5 Air Coolers

Water is usually injected upstream of the reactor effluent aircooler to prevent ammonium bisulfide (NH4HS) (and sometimesammonium chloride (NH4Cl))deposit formation in piping andtubing. The water solution of NH4HS may be very corrosivetowards carbon steel. Corrosion severity has been correlated toa factor Kp, which is defined as the product of mole percentconcentrations of ammonia and hydrogen sulfide in the processstream before water injection. Where Kp exceeds 0.05, theprocess stream velocity in piping (downstream of the waterinjection point) and in any point of the air cooler must notexceed 20 ft/sec. Water injection rate shall keep NH4HSconcentration in water below 2% - 4%.

The reactor effluent air cooler is usually high corrosionallowance carbon steel (e.g., 10 gage minimum tubing with 0.25inch corrosion allowance headers). Alloy tubes at Kp valuesless than 0.4 may not be justified. Much depends on keepingactual velocities below 20 ft/sec and proper symmetrical designof aircooler inlet and outlet piping. Minimum stream velocityof 10ft/sec should also be maintained to prevent water phaseseparation and deposit of precipitation which increasecorrosion.

If Kp exceeds 0.4, alloy tubing (duplex SS, Incoloy, etc.)should be used along with lined tubesheet (in some cases it maybe more economical to line the whole header). For alloy tubing,the upper limit of the velocity stream can be raised to 30ft/sec.

Fractionation section air cooled exchangers should be carbonsteel, unless very high wet H2S concentrations exist. Then theuse of a filming amine inhibitor or a corrosion resistant alloyshould be considered.

5. 3 .6 Towers

Towers should consist of carbon steel with a 0.125 inchcorrosion allowance, unless there is corrosive hot or aqueousH2S. In hot service, 410S SS cladding may be required. AqueousH2S usually needs a 0.25 inch corrosion allowance.

5. 3 .7 Drums

Materials for drums are consistent with towers, except thatgunite is used with a 0.125 inch corrosion allowance or 0.25inch corrosion allowance in aqueous H2S. The minimum materialmay be set by hydrogen partial pressure.

5. 3 .8 Pumps

Pumps should consist of cast iron or carbon steel impellerswith steel cases. Above 450°F-550°F, 12Cr or CA6NM cases andimpellers should be used. Cast or ductile iron should beconsidered for water service.

5. 3 .9 Sour Water Piping

See 5.2.2, paragraph 9. Monel shall not be used in high ammoniaconcentrations.



5. 3 .10 Heaters

Charge heaters with H2 require austenitic stainless steeltubes, Type 347, unless concentration of H2S is very low. Type321 SS has also been used. Stainless steel return bends shouldbe wrought rather than cast both to obtain superior quality andto avoid sigma phase embrittlement (see 4.10.5).

Fireside deposit corrosion problems must be considered whenselecting tube materials. Without H2 in the heater, 9Cr-1Motubes are used. Most fractionation heaters can be carbon steel,unless considerable H2S or high outlet temperatures areinvolved. 5Cr-0.5Mo may be required for H2S. A lower Cr alloymay be required for strength at elevated temperature.

5. 3 .11 Piping

Piping is selected per hydrogen attack and H2S or H2 - H2Scurves. Materials should be used that minimize scaling in thereactor feed circuit. Much of the reactor circuit is austeniticstainless steel. Cr-Mo steels may be satisfactory attemperatures above 500°F - 550°F upstream of hydrogeninjection.

For the guidelines on the reactor effluent piping downstream ofthe water injection point see 5.3.5. If this piping is subjectto high corrosion rates and premature failure despite takingthe recommended measures (proper process stream velocity,etc.), the use of a corrosion resistant alloy (e.g., Incoloy825) should be considered.

If corrosion inhibitors and antifoulants are used, carefulselection is required to protect the water separationcharacteristics of products, such as Avjet.

5.4 Catalytic Reforming Units

5. 4 .1 General

Materials selection in catalytic reforming units is almostentirely based on considerations of resistance to hightemperature hydrogen attack.

5. 4 .2 Reactors

Hotwall reactors are 1.25Cr-0.5Mo, which has adequate strengthat design temperatures and is resistant to hydrogen attack.Coldwall reactors are carbon steel with 1.25-0.5Mo nozzles.Stacked reactors for continuous regeneration are 1.25Cr-0.5Mo.Internals are usually 410 or 316 stainless steel. Newer unitsuse 316, which is not vulnerable to the embrittlement problemsof 410. Because of the high chloride levels in the catalyst,consideration must be given to the potential for chloridestress corrosion cracking, particularly during downtimes.

5. 4 .3 Exchangers

New combined feed exchangers are usually true countercurrentflow. Material requirements are set by the hydrogen partialpressure. Tubes, channels, and shells are usually 1.25Cr-0.5Mo.When specifying materials, it should be noted that it is nearlyimpossible to accurately predict temperatures in an exchanger.



Parts, such as shells, should be of one material or thematerial breaks should be conservative. True countercurrentflow bundles should not be used for high maintenanceexchangers, such as unifiner feed/effluent exchangers, becausethey are difficult to assemble.

Since sulfur is not involved in the platforming section of theCRU, all other exchangers can usually be carbon steel, as longas there is no potential for hydrogen attack.

5. 4 .4 Air Cooled Exchangers

All air cooled exchangers are usually carbon steel.

5. 4 .5 Condensers - Coolers

All condensers and coolers can be standard admiralty, exceptwhere there may be high ammonia concentrations. Admiralty canbe used in many of the condensers and coolers if suitablehandling procedures are used before opening. The effluentcooling train is the only area subject to problems. Admiraltyor aluminum brass bundles should be water washed before beingopened to avoid ammonia cracking (see Section 4.6.7).

5. 4 .6 Piping

The reactor section piping must meet hydrogen attack criteria.The hot section will usually be 1.25Cr-0.5Mo. Most other pipingcan be carbon steel.

5. 4 .7 Pumps

Pumps should have a steel case and cast iron or carbon steelimpellers to 450°F - 550°F and 12Cr or CA6NM above.

5. 4 .8 Heaters

The platformer charge and intermediate heaters use 1.25Cr-0.5Moheaders and either 2.25Cr-1Mo or 9Cr-1Mo tubes. Although the2.25Cr-1Mo has been used successfully for many years, new unitsneed the increased oxidation resistance of 9Cr-1Mo because of ahigher flux rate and higher metal skin temperature. The lattercan be above 1150°F at the end of runs. Other heaters canusually have carbon steel tubes.

5. 4 .9 Recycle Compressor

Recycle compressors are subject to corrosion of the rotatingelement by chlorides and have the potential for hydrogenembrittlement. The machines are usually washed before opening,which cleans out the soluble chloride deposits. Welding andheat treating restrictions are applied to the compressors tominimize potential cracking problems. Suction lines should betraced or jacketed to minimize moisture during service.Minimizing moisture should minimize corrosion and deposits.Suction knockout drums and demisters should be specified.

5. 4 .10 Special Corrosion Problems

Corrosion is usually at a minimum during operation as thehigher temperatures do not allow condensation of corrosivecompounds. But the feed may contain some hydrogen and the



catalyst contains chlorides. Resulting from hydrogeninteraction with these substances, hydrogen chloride gas orammonia may form. On cooling and condensation, when componentis shutdown, formation of corrosive hydrochloric acid orammonium chloride may occur. This may plug the air cooledreactor effluent condenser and cause deposit problems in therecycle compressor.

To prevent this, the following equipment is water washed:

1. Effluent coolers.

2. Flash drum separators.

3. Recycle compressors.

4. Strippers and associated piping.

A 5 weight % sodium bicarbonate solution is a good choice forthe washing medium as the slight alkalinity overcomes the acidhydrolysis of ammonium chloride when the water is introducedinto previously dry equipment.

In order to remove hydrogen chloride from recycle gases, HCltraps may be installed in the lines leading from theseparators.

5.5 Fluid Catalytic Cracking Units

5. 5 .1 General

The feed system on an FCCU is similar to a crude unitatmospheric preheat section. Somewhat less sulfur corrosionshould be expected, since at least some of the sulfur compoundsare thermally converted to H2S in the crude unit or in feedhydrotreaters, if used. The material selection is based onhaving at least 1% sulfur in the feed. The feed heater useseither 5Cr-0.5Mo or 9Cr-1Mo tubes to minimize sulfur corrosionand give higher strength and oxidation resistance. Exchangertubes go from carbon steel at 500°F to 5Cr-0.5Mo, with 12Crover 650°F. Piping above 550°F should be 5Cr-0.5Mo from thecorrosion and erosion standpoint. Some units have 9Cr-1Mopiping above 650°F in both the fresh feed and recycle circuits.

5. 5 .2 Reactor Section

Many of the older units have carbon steel hotwall reactors cladwith 410 stainless steel. Over the years, the cladding hascorroded or eroded, and refractory linings have been required.Current practice is to use a cold shell design with refractorylining and a carbon steel shell. A 4 to 5 inch layer of mediumweight refractory, such as A.P. Green Greencast-45LGR (orequal), is generally specified.

If they are large enough (greater than approximately 30inches), fresh feed risers are refractory lined. Single layervibration cast refractory is preferred for riser lines toprovide both erosion protection and insulation. A 4 to 5 inchlayer of Premier AR-400 (or equal) refractory is typical.Vibration cast linings generally contain 3 weight % of SSneedles for increased resistance to cracking. If the lines aresmaller, hardfacing, such as chromium carbide, cobalt basedalloys (Stellites), nickel - chrome, boron alloy (Colmonoy), or



equal, are used. Risers can be carbon steel if kept belowapproximately 750°F by the refractory and internal insulation.Higher temperature hardfaced lines need to be 1.25Cr-0.5Mo fromstrength considerations.

All catalyst handling lines are refractory lined or hardfaced,depending on size to minimize erosion problems. The reactorinternals, such as cyclones, are carbon steel or low alloy,depending on the strength required, and are refractory linedfor erosion protection. Above 850°F, potential of carbon steelloss of strength, resulting from long-term graphitization,should be considered.

Nevertheless, current practice is to use carbon steel for allreactor internals, such as cyclones, stripper baffles, steamdistributors, at design temperatures up to 1050°F. Itemsrequiring high strength, such as vessel lugs, supports, orcyclone hanger rods, can be of low alloy or stainless steel.

General practice is to avoid the use of austenitic stainlesssteels for reactor internals. If stainless steel is usedbecause of higher sulfur and temperature, stabilized grades,such as 321 SS or 347 SS, should be used to minimize potentialintergranular cracking problems due to polythionic acidformation during downperiods.

5. 5 .3 Regenerator

Regenerators are refractory lined cold shell carbon steelvessels. With regeneration temperatures rising from the 1100°Frange to 1250°F and above, internals, such as cyclones andtheir support systems, have gone from carbon steel to2.25Cr-1Mo and finally to Type 304H stainless steel. 2.25Cr-1Mocyclones carburize at temperatures over 1200°F and are verybrittle at room temperature. New cyclone installations havebeen with Type 304H SS. Types 321 SS and 347 SS are not usedbecause of much lower allowable stress levels. Although Type304H sensitizes, downperiod intergranular cracking conditionsare not as favorable as in the reactor. After long exposure tohigh temperature, desensitization of 304H SS is supposed tooccur. It can sensitize again during slow shutdown cooling, butexperience has shown that polythionic acid cracking failures inregenerator are rare.

It is often desirable to install refractory linings on theoutside of regenerator internals, in addition to any refractoryinside, if exposure to turbulent catalyst flow inside theregenerator occurs. If air distribution rings are employed,external refractory linings are also common. Much of theregenerator internals subject to erosion are lined using anintermediate density or phosphate-bonded castable. Such liningsshould contain metal fiber for reinforcement and are generally1 inch (25 mm) to 2 inch (50 mm) thick.

Many of the problems experienced with austenitic stainlesssteel cyclone systems are due to the higher thermal expansionand to distortion problems. Use of spray or quench water to thecyclones during temperature excursions is no longer recommendeddue to damage caused by spray impingement on hot surfaces.



Design at over 1300°F requires a detailed investigation torecommend the most suitable materials.

2.25Cr-1Mo is usually satisfactory for internals in the lowerpart of the regenerator, except if temperatures exceed 1300°F.

5. 5 .4 Slide Valves

Older slide valve designs were generally of hot wallconstruction with internal refractory lining or hard facing forerosion protection only. Slide valves designed to approximately1250°F were typically 1.25Cr-0.5Mo or 2.25Cr-1Mo at the highertemperature end. Above 1250°F, austenitic stainless valves wereused. These were, however, subject to polythionic acid attackduring down periods. Current practice is to use cold wall slidevalve designs in both reactor and regenerator service. Coldwall designs typically have carbon steel valve bodies withvibration cast refractory for insulation and erosionprotection. Valve internals are generally low alloy orstainless steel depending on temperature.

5. 5 .5 Major Lines

The reactor overhead line that carries cracked gas from thereactor to the main fractionator is typically unlined1.25Cr-0.5Mo. Materials selection is based primarily on theneed for strength and resistance to high temperaturegraphitization. Localized attack by high temperature H2S ispossible at “cool” spots where heat is drawn away by externalsupports (e.g., a protective coke barrier does not form at thelower temperature). However, the potential for H2S attack inthis environment is not a strong driver for upgrading to moresulfidation resistant alloys. Although normally solved throughdesign and not materials upgrading, fatigue cracking hasoccurred in reactor overhead lines, especially at miters. Thesource of the stress is the differential thermal growth betweenthe reactor overhead and the fractionator inlet nozzle that canplace high strains on the piping each time the reactor iscycled.

With today’s high temperature regenerators, flue gas exits theregenerator at 1250°F (675°C) to 1425°F (775°C). Erosion fromcatalyst fines, oxidation resistance, carburization resistance,and the need for high temperature strength are the primaryconcerns. In flue gas ducts, erosion is more of a problem atelbows than in straight runs. Erosion is particularly severein, and just downstream of, restriction orifices and the slidevalve. Piping materials for the regenerator overhead line aretypically refractory lined carbon steel. When a power recoveryturbine in used, inlet piping is typically uninsulated 3xxseries stainless steel to avoid refractory particles enteringthe turbine.

Catalyst transfer piping is usually constructed of carbon orlow alloy (5Cr-0.5Mo, 9Cr-1Mo) steel with an internalrefractory lining. Previously, a dual-layer refractory liningwas used, supported by hexmesh. As refractory technologyimproved, the refractory of choice has become the single layer,vibration cast, heavy weight refractory, supported by vee



studs. The quality of this lining has been further improved byreinforcement with stainless steel (Type 304) needles.

Another problem is the failure of several large diameterexpansion joint bellows in various lines. The standard bellowsmaterial has been 321 SS, which is very susceptible to chloridestress corrosion cracking when exposed below the dew point.There are sufficient chlorides available to cause failures veryrapidly. Bellows with much better chloride stress corrosioncracking resistance, such as Inconel 625 and Incoloy 825, arenow being recommended in some services.

5. 5 .6 Fractionation and Gas Recovery

The main fractionator is handled similarly to a crude unitatmospheric tower with 410S clad part way up the tower toapproximately 500°F. The gas recovery section handles largeamounts of H2S and NH3 and should have full protection fromsulfide stress corrosion cracking and hydrogen embrittlementand/or blistering. All equipment exposed to wet H2S should bestress relieved with hardness after PWHT that does not exceed200 Brinell. Critical problem areas are the overhead systems ofthe fractionator, depropanizer, absorber - deethanizer, andaround the compressor. For some extreme cases, includingprevious experience with severe hydrogen blistering, the use ofHIC resistant steel (see Section 4.6.2) should be considered.

Brinell hardness of piping welds, base metal, and heat affectedzone in wet H2S service is limited with 200 Brinell.

Sulfur corrosion rates are usually not as high as on a crudeunit. 5Cr-0.5Mo lines are used over 550°F, although some9Cr-1Mo has been used at higher temperatures. Low temperatureproblems with deposit buildup around compressors and cyaniderelated corrosion problems around the absorber must berecognized. Copper base alloys and Monel are usually subject tovery high corrosion rates and in some cases to stress corrosioncracking because of the high ammonia concentrations.

The compressor can usually consist of standard materials fromthe corrosion standpoint, but the 90,000 psi maximum yieldcriteria must be used. Compressor material restrictions arespecified in GEMS. More specific recommendations on cyclones,refractory, and slide valves are specified in FCCU cyclone GEMSand in Texaco slide valve purchase recommendations.

5.6 Alkylation Units

5. 6 .1 Reactor Section

Texaco alkylation units use 98% H2SO4 as the catalyst. Thereaction is run in the contactors at low (20°F - 50°F)temperature, which allows considerable carbon steel to be used.Due to the below ambient temperature, carbon steel withimproved notch toughness, such as A 516, is required,particularly for heavier walled vessels. Carbon steel piping isadequate from the corrosion standpoint around the contactors ifthe velocities are low (2 ft/sec range). Welds in contact withsulfuric acid in some cases are post weld heat treated tominimize hydrogen cracking and/or preferential corrosion ofweld metal or heat affected zones. Cold worked metal (usually



bends) is also often stress relieved. Weld root beads are oftenmade using gas tungsten arc welding to avoid weld penetrationinto the line to minimize turbulence that can substantiallyincrease corrosion rates in sulfuric acid.

At higher velocities or in turbulent areas, Carpenter 20Cb3 isused. Alloy 20 (the cast equivalent of Carpenter 20Cb3) iscommonly used for acid pumps. Acid pump suction and dischargelines may need to be 304 or 316 SS in highly turbulent areasfor the first few feet. Vitrified tile is used for acid drainlines. Valves in the reaction section are commonly carbon steelwith Alloy 20 trim or all Alloy 20.

The contactors are very specialized reactors. Many of the linesin turbulent areas are Carpenter 20Cb3. The impeller is usuallyNi-resist, which is a nickel austenitic cast iron. Thecontactors have a 0.125 inch corrosion allowance. The largerefrigeration bundle in the contactor has had erosion problemson the contactor side in the area around the tube supports.

5. 6 .2 Fractionation Section

The rest of the unit is carbon steel, usually with 0.125 inchcorrosion allowance. There are a few problem areas in thefractionation section. Potential problems from causticcarryover during neutralizing must be considered in specifyingtowers and reboilers. Unless the caustic is completely washedout, it can concentrate and cause stress corrosion crackingproblems. If carryover is a possibility, equipment should bestress relieved.

Depending on the specific fractionating scheme, some toweroverhead systems, such as the deisobutanizer and depropanizer,can run at low pHs due to sulfur ester breakdown. Corrosion inthe tray and overhead condenser or cooler can result. Many ofthe upper trays in these towers have been replaced withaustenitic stainless steel. Inhibitors have been used in theoverhead systems but can be troublesome because of thedifficulty of keeping them in solution in the light ends beingprocessed.

Care must be taken to control and minimize any ammoniainjection to raise the overhead pHs, since severe corrosion andstress corrosion cracking of admiralty or other copper basedalloy condensers can result. Some of the older units have hadproblems with inadequate acid neutralizing.

5. 6 .3 Compressor

The compressor can consist of standard materials, except forthe hardness, yield strength, and heat treating restrictionsspecified in GEMS.

5.7 Gasification Units

5. 7 .1 General

The specific materials selected for gasification units willdepend on process design. In refineries, gasification units areused for hydrogen generation. The same units can be used to



make petrochemical feedstocks, and the produced syngas can alsobe used for power generation in a combustion turbine.

5. 7 .2 Oxygen System

Carbon steel piping is used from the GSU (Gas Separation Unit)to the process unit boundary. Carbon steel piping is notrecommended within the gasification unit battery limit becauseof the fire hazard. Carbon steel must be meticulously cleanedand always be under a nitrogen blanket when not in service.Since the oxygen piping around the feed injector will be opento atmosphere periodically, carbon steel piping is notpractical.

All process piping in contact with oxygen within the unit mustbe 304L SS as a minimum.

Monel 400 or Inconel 600 must be used as a fire break withinapproximately 25 feet of the gasifier reactor. The normallocation of this piping spec break is upstream of the oxygenflow control valve and this 25 foot section of piping willterminate at the process feed injector. Monel valve bodiesshould not be used for the steam purge valves into the oxygenpiping as valve body distortion has occurred in hightemperature steam service. For high temperature steam purgevalves, Inconel 600 is the recommended material.

The Compressed Gas Association Pamphlet G-4.4 should beconsulted for an overview of oxygen service materials andcleaning requirements. However, the copper base alloys forvalve trim, as recommended in this pamphlet, will not be used.Copper base alloy valve trim will experience scouring and valveleakage.

5. 7 .3 Charge Oil System

Materials for the charge oil will depend on the temperature andthe sulfur content in the oil. Carbon steel will be used below550°F. Usually, 5Cr-0.5Mo or 9Cr-1Mo will be required at highertemperatures.

5. 7 .4 Coke Slurry System

Erosion of piping in the slurry system will be a problem.Velocity should be designed below 3 feet per second by pipesizing. Piping configuration will use long radius bends,laterals, and special wear pieces (i.e., basalt lining aroundpump discharge, mag meters, and other high velocity zones).

Pipe should be XXS or schedule 160 carbon steel as a minimum.

5. 7 .5 Steam System

Whenever possible, plant steam will be used, as this eliminatesthe need for onsite water treating and steam generation.

If a waste heat boiler is specified in the process design, theunit will have fire tubes with the steam generated on the shellside.



The materials for the tubes will be dependent on the metaltemperature and composition of the syngas. Usually 1.25Cr-0.5Moor 2.25Cr-1Mo steels have been adequate. The face of the tubesheet will be protected with a high alumina refractory rammingmix or with specially cast alumina bricks. The tube entrancewill be water cooled because of the high heat flux. Severalplants have encountered problems with overheating at the tubeentrance from high heat flux due to low cooling water flow,which leads to carburization and metal dusting in CO/CH4 richsyngas. The shell side of the waste heat boiler will be carbonsteel.

5. 7 .6 Gasifier Section

The gasifier vessel and quench chamber will be 1.25Cr-0.5Mo forhigh temperature strength and resistance to hydrogen attack.

The Nelson curves (API RP 941) will be followed in selectingthe gasifier shell material. The gasifier vessel will beinternally lined with refractory brick. The corrosion allowanceon the shell will be 0.25 inch to accommodate areas of theshell behind the refractory where dewpoint corrosion may occur.This is especially common around the thermocouple nozzles. Theexterior of the gasifier will not be insulated.

Thermocouple nozzles should be insulated to prevent dew pointcorrosion inside the nozzle necks.

The quench chamber will be clad with 316L SS. Incoloy 825 maybe considered where the chlorides in the quench chamber areexceptionally high (i.e., over 1,000 ppm). Formic acid formsduring gasification. Therefore, the quench chamber andinternals will require materials that are resistant to organicacids. The internals will usually match the clad material,except that Incoloy 825 is required for the quench ring and diptube where alternate wetting and drying will build a salty ashlayer which may stress corrosion crack stainless steels. Thedraft tube is usually 316L SS as are most of the otherinternals in the quench chamber. The baffles and gussets in theoverhead of the quench chamber are 1.25Cr-0.5Mo steel with a0.25 inch corrosion allowance on each side.

The process burner will be 347 SS for the charge oil componentsand Incoloy 825 for any parts in contact with oxygen slurry.Inconel 600 components have failed due to polythionic acidstress corrosion cracking in sulfidic corrosion service andtherefore should be avoided. Inconel 625 can be used as analternative to Incoloy 825. Natural gas feed injectors made ofIncoloy 800H have experienced severe metal dusting in preheatedgas feed at 1100°F. Inconel 600 has worked well in thisapplication.

The feed injector main flange will be 1.25Cr-0.5Mo steel tomatch the gasifier vessel. Cooling water piping above the feedinjector flange will be XXS or schedule 160 1.25Cr-0.5Mo alloysteel to the control valve. Carbon steel will be used for theremainder of the cooling water piping. The feed injectorcooling water piping tank will be carbon steel with an epoxyliner. As an alternative, carbon steel with a 0.12 inch



corrosion allowance may be used for the tank provided acorrosion inhibitor is used in the cooling water.

5. 7 .7 Syngas Scrubbing Section

The gas outlet line to the carbon scrubber is carbon steel with0.25 inch corrosion allowance provided the gas outlettemperature is below 450°F. At higher gas outlets, 25Cr-0.5Molow alloy steel will be required to prevent hydrogen attack perthe Nelson curves in API RP 941. Full heat conservation will beapplied to the gas outlet to prevent dewpoint corrosion.

The syngas scrubber will be carbon steel or 1.25Cr-0.5Mo lowalloy steel per API RP 941. The syngas scrubber will be postweld heat treated for sour service. A 0.25 inch corrosionallowance will be used where the bottoms scrubber water has apH of 5.5 or higher. For lower pH values, the syngas scrubbershould be clad with 316L SS. The internals and trays in thesyngas scrubber will be 316L SS.

5. 7 .8 Water System

The water system is characterized by chlorides, low pH due toformic acid, and solids which accelerate erosion of piping andvalves.

The soot water produced with natural gas or liquid feed to thegasifier is not erosive due to the soft nature of the soot.

For petroleum coke gasification, erosion is not considered aserious problem in the slag, and black water water service withan experienced piping design which limits the velocity byproper line sizing, etc. Black water piping will experienceerosion around control valves and pump discharge where thevelocity is very high. At these locations, special wear piecescan be fabricated or an extra erosion allowance can be applied.

The preferred piping for black water and slag is carbon steelwith a large corrosion allowance. Even if the velocity is nothigh, erosion/corrosion on the carbon steel will still requirea good corrosion allowance of 0.25 inch minimum.

Where the pH of the black water is low from formate andinsufficient ammonia production, alloy piping must beconsidered. A pH of 5.5 is the lowest that can be tolerated oncarbon steel for the high pressure systems and this must befrequently monitored for wall thickness. For the low pressureslag piping downstream of the lockhopper, a lower pH could betolerated on the carbon steel with little consequence in theevent of a piping leak.

If the pH of the black water is below 5.5, then 316L SS can beused for low chloride conditions. The 316L grade is selectedfor corrosion resistance to the organic acid. The 316L can beused for chloride levels up to 150 ppm provided that there areno zones where the chloride salts will concentrate by wettingand drying. This did occur at one plant in a heat exchangerbundle. Stress corrosion cracking (SCC) was also experienced in304 and 316 SS U bend corrosion coupons in plant black waterservice where alternate wetting and drying occurred.



If the pH is low and the chlorides are high, then this becomesthe case where the duplex stainless steel or Incoloy 825 pipingmust be used. Duplex SS piping will be alloy UNS S31803 orS32750 with the lowest installed cost being the majorconsideration. Only highly experienced duplex SS pipingfabricators should be selected. For valve bodies in highchloride service, carbon steel weld overlayed with 316L weldmetal or SS casting grade CF-8M (316 SS) are utilized. Thecasting grade CF-8M will have sufficient residual ferrite toresist SCC. Pump casings can also be martensitic stainlesssteel grade CA6NM where increased erosion resistance isdesired. The casting grade CA6NM will be given the heattreatment called for in NACE MR0175 for resistance to sulfidestress corrosion cracking.

Grey water piping will experience erosion around control valvesand pump discharge where the velocity is very high, especiallywhere flashing occurs. At these locations, special wear piecescan be fabricated or an extra erosion allowance can be applied.For ball valve trim, 316 SS with a nickel boron diffusioncoating has performed well. High pressure letdown valves at theflash drum will be angle valve designs with tungsten carbidetrim. The preferred piping for grey water is carbon steel witha large corrosion/erosion allowance of 0.25 inch minimum. Alloypiping in grey water should not be required with ammoniarecycle from condensate with the resulting subsequent elevationin system pH. Low pressure grey water pumps should be Ni-hard,abrasion resistant cast iron, ASTM A 532 Class III.

5. 7 .9 Trim Cooler and Condensate Strippers

The line coming to the trim cooler will be carbon steel with aheavy corrosion allowance of 0.25 inch. The trim cooler will becarbon steel post weld heat treated for wet H2S service with a0.25 inch corrosion allowance. Tubes for the trim cooler willbe 304 or 316 SS and it is noted that the pH of the condensatein the tubes should be used to select the tube material. For pHbelow 4.5, 316 SS should be selected for its superior corrosionperformance in carbonic acid.

The trim cooler KO drum will be carbon steel with 304L SScladding. The trim cooler KO drum pump around will be 304L or316L SS piping with a CF-8M pump case and impeller. Carbonsteel piping can be considered for the pump around if the pH isabove 5.5 and the corrosion allowance should be a minimum of0.25 inch. The trim cooler KO drum bottoms piping and transferpiping to the condensate stripper will be carbon steel with0.25 inch corrosion allowance.

The condensate stripper feed product exchanger shell is carbonsteel with a 0.25 inch corrosion allowance and PWHT for wet H2Sservice. The tubes will be 316 SS (expect 50 ppm level of HCNin the tubes). The condensate stripper vessel is carbon steelpost weld heat treated for wet H2S service. It will have a0.125 inch corrosion allowance and will be internally linedwith acid resistant concrete (i.e., Resco FA-22 or equal).Trays and tray supports are 316L SS and packing will be 316 SS.The reboiler is carbon steel with carbon steel tubes and carbonsteel piping. The tube side of the reboiler is PWHT for wet H2Sservice.



The pump around piping is carbon steel with 0.25 corrosionallowance. Stainless steel Type 316L should be considered forthe pump around piping downstream of the pump to the inlet ofthe condenser where the velocity is higher. The pump materialis recommended in Alloy 20 (casting grade CN-7M) because of thevelocity and cyanides. The condenser tubes are titanium grade 2where the cyanide levels and velocity are high (expect 150 ppmlevels of HCN).

The bottoms pump is carbon steel with a Ni-resist (ASTM A 439)impeller and the bottoms piping is carbon steel with 3 mm(0.118 inch) corrosion allowance. Where the stripped condensatebottoms has an additional bottoms cooler, the shell will bepost weld heat treated carbon steel and the tubes will becarbon steel.

5. 7 .10 Gas Clean Up System

Acid gases, such as H2S and CO2, are removed in sour gastreating units. Selection of materials will follow theguidelines in the section concerning these units.

5.8 Delayed Coking Units

5. 8 .1 Coke Drums

Coke drums have been made of carbon steel, Carbon - 0.5Mo, and1Cr-0.5Mo.

Bulging and subsequent cracking have been a continuing problemwith many drums. Drums have been clad with 405 but 410S ispreferred. The clad is required to minimize sulfur corrosion.

Since the drums operate in the 850°F - 900°F temperature range,elevated temperature strength and resistance to microstructuralchange is desirable. Carbon steel drums have relatively poorstrength and have a history of bulging problems. Carbon - 0.5Mohas good strength but can suffer a severe loss in notchtoughness. The decrease in notch toughness makes carbon - 0.5Modrums susceptible to cracking problems. 1Cr-0.5Mo has goodstrength and does not appear to suffer the severe toughnessloss experienced by carbon - 0.5Mo.

Current material recommendations are for 1Cr-0.5Mo clad with410S for corrosion protection.

The frequent thermal cycles experienced by the coke drums oftenresult in fatigue failure. Typically, coke drums are operateduntil fatigue cracks in the shell and nozzles increase to apoint to be considered unsafe, or the bulging and distortionare so severe that the drums are considered structurallyunsound, or the distortion is so severe that the piping can nolonger be connected to the drums because of misalignment.

5. 8 .2 Coking Heater

Due to high outlet temperature and need for elevatedtemperature strength and resistance to oxidation andsulfidation, 9Cr-1Mo is used for heater tubes.



5. 8 .3 Fractionator

The fractionator is handled as a crude unit atmospheric tower.Coker stocks are expected to be high sulfur. 410S clad isrequired in areas operating above 500°F. A coker may processcrude, so consideration must be given to naphthenic acidproblems. Many coker charge stocks have high nitrogen contents,so careful material selection is required, particularly whenMonel or copper base alloys are considered in the fractionatoroverhead and gas compression systems (because of potential forammonia formation).

5. 8 .4 Towers

Towers vary on a coker, depending on individual plantrequirements. Use of carbon steel with a 0.125 inch corrosionallowance where the H2S is low and a 0.25 inch corrosiveallowance where H2S concentrates is satisfactory. Most towers,other than the fractionator, are not hot enough to requireclad. Clad protection would be required above 500°F for sulfurcorrosion or above 450°F if naphthenic acid problems are apossibility.

5. 8 .5 Drums

Carbon steel with 0.125 inch corrosion allowance issatisfactory for areas below 500°F and low H2S. Carbon steelwith a 0.25 inch corrosion allowance or 0.125 inch corrosionallowance plus gunite is used for wet high H2S.

5. 8 .6 Piping

Hot piping around the coker heater and coke drums to thefractionator is usually 9Cr-1Mo. Piping off the fractionatorfollows the same material temperature breaks as for the crudeunit. That is, carbon steel to 550°F, 5Cr-0.5Mo to 650°F, and9Cr-1Mo above 650°F. Most of the sulfur left will be verythermostable after exposure to coking conditions. The highcorrosion rates that might be predicted for either 5 or 9Crshould not be expected, because most of the sulfur compoundsthat would form H2S thermally have been removed. Careful use ofMonel is required because of possibility of high ammoniaconcentrations. 0.25 inch corrosion allowance carbon steelpiping is usually satisfactory for wet, high H2S areas.

5. 8 .7 Exchangers

Material selection depends on the unit configuration, butsulfide corrosion problems usually set the exchangermetallurgy. As a generalization, exchanger materials selectedfor crude units are satisfactory.

5. 8 .8 Condensers - Coolers

The standard admiralty condenser or cooler is satisfactoryexcept where high pHs resulting from high nitrogen feed andammonia formation are present. Water draw pHs above 8 caused byammonia can cause high corrosion rates (and in some casesstress corrosion cracking) on admiralty and other copperalloys. Carbon steel may be more satisfactory from the processside if the plant can accept it on the water side.



5. 8 .9 Air Cooled Exchangers

The basic air cooled exchanger is carbon steel. Areas with highH2S require thicker tubes and 0.25 inch corrosion allowanceheaders. 70-30 Cu-Ni can be used in high H2S areas only if thenitrogen content of the feed is low. This is particularly trueof the fractionator overhead and gas compression system.

5. 8 .10 Compressor

The coker gas compressor handles high H2S and usually highammonia gas. All precautions to prevent sulfide crackingproblems must be taken. These precautions include welding andhardness, yield strength, and heat treating restrictions.

5.9 Sour Water Treating

Sour water stripping units have been used for many years to minimize theH2S and NH3 released in effluent water. Sour water originates fromaccumulator, reflux, and knockout drums at various refining units,including crude units, catalytic cracking, hydrocracking, hydrotreating,and reforming units. Consequently, potential corrosive agents includehydrogen sulfide, ammonia, chlorides, cyanides, mercaptans, andphenolics.

Due to increased pollution requirements, these units have been modifiedto more effectively strip waste water. The result of the increasedstripping is that corrosion problems have increased. Most of Texaco'snew or modified units are non-acidified with overhead and/or refluxcondensing. The major problem areas in these units are the overhead andreflux condensers, with some problems in the feed bottoms exchangers.The overhead and/or reflux condensers are usually air cooled to minimizewater usage.

Service experience with the new designs verifies the potential overheadsystem problems in terms of corrosion and hydrogen cracking. Duplexstainless steels, such as 3RE60, 2205, or 2507, and in some casestitanium and aluminum alloys, are being used for overhead or refluxcondensers tubes in an attempt to minimize corrosion and the probabilityof chloride stress corrosion cracking. The corrosion problem isprimarily due to ammonium hydrosulfides. Because of the high ammoniaconcentration, copper base alloys and Monel cannot be successfully used.

Lines are usually cement lined, subject to size restrictions and/orlimitations. A 0.25 inch corrosion allowance is used for small lines.

The stripper towers are generally made of carbon steel with heavycorrosion allowance. The internals are carbon steel, 316 SS, oraluminum, depending on corrosion experience.

Exposed internals and nozzle liners are 316 or 316L if welded.

Feed bottoms exchangers are carbon steel to approximately 180°F. Above180°F, tubes are the duplex SS described previously. Feed and bottomspumps are steel, ductile iron, or Ni-resist.

Overhead and/or reflux air coolers have 316L lined headers and tubesheets with the above duplex SS tubes. Reflux pumps are CF-8M, the castequivalent of Type 316.



If significant problems develop with the present stainless steel shelland tube and air cooled exchangers, titanium may be considered.

All unprotected carbon steel equipment in sour water service should bepost weld heat treated per GEMS G-7M to avoid hydrogen stress cracking.In some extreme cases, HIC resistant steels (see Section 4.6.2) may beused.

Water soluble filming amine corrosion inhibitors can be injected intothe overhead line to help control both corrosion and hydrogen damage.

5.10 Sour Gas Treating Units

5. 10 .1 General

Most of the sour gas treating units in refineries use MEA, DEA,DGA, or MDEA (monoethanolamine, diethanolamine, diglycolamine,or metyldiethanolamine). The problem areas are around theregenerator where the H2S and CO2 are stripped from thesolvent. Some problems have occurred in the feed line to theregenerator where the pressure on the rich amine is reducedahead of the tower. The pressure reduction may cause flashingand increased corrosion rates. Most of the unit is carbonsteel. The regenerator and hot lines and overhead line shouldhave a heavy corrosion allowance. The regenerator reboilerusually has 410 SS tubes. The reclaimer (if used) hasaustenitic stainless steel tubes. In several cases, pitting on410 SS reboiler tubes has been observed, and they were replacedwith austenitic SS. The corrosion rate depends on the metalskin temperature (problems arise above 300°F steam temperature)and the solution loading.

The amine solution can crack carbon steel, so all lines,towers, exchangers, drums and other equipment, and piping inrich amine or lean amine (but not fresh amine) are post weldheat treated.

Some serious corrosion problems may exist in regeneratoroverhead system. Currently, duplex SS tubes are recommended forregenerator overhead condensers. Regenerator overhead corrosioncan be minimized by operating the regenerator such that 0.5%amine is taken overhead.

Depending on solution loading and temperature, some plants havehad apparent success with titanium in both reboilers and watercooled overhead condensers, where other materials had failed.Many of the new units have air cooled overhead condensers.Aluminum has worked reasonably well but is vulnerable to highvelocity erosion and pitting from heavy metal contamination.

To minimize the corrosion in the rich amine, it is recommendedthat solution loading be kept below 0.34 mole of acid gas(H2S + CO2) per mole of amine. Sidestream filtration is alsovery beneficial from a corrosion point of view.

5. 10 .2 Materials Selection

1. Absorber

a. Shell - CS, 1/4 inch CA, PWHT.

b. Trays - 410S or austenitic SS.



2. Lean Amine Cooler

a. Shell side (cooling water) - CS, 1/4 inch CA.

b. Tube side - CS, 1/4 inch CA (except tubes), PWHT.

3. Lean - Rich Amine Heat Exchanger

a. Shell side (lean amine) - CS, 1/4 inch CA, PWHT.

b. Tube side (rich amine).

(1) Tubes below 200°F - CS.

(2) Tubes above 200°F - austenitic SS.

(3) Tubesheet, channel, and cover - CS, 1/4 inch CA,PWHT.

4. Regenerator (Stripper)

a. Shell - CS, 1/4 inch CA, PWHT. Alternate material -410S clad CS.

b. Trays - austenitic SS.

5. Overhead Condenser

a. Shell side (cooling water) - CS, 1/4 inch CA.

b. Tube side.

(1) Tubes - duplex SS.

(2) Tubesheet, channel, and cover - CS, 1/4 inch CA,PWHT.

6. Reflux accumulator - CS, 1/8 inch CA, gunite lined, PWHT.

7. Reboiler (steam in shell side). Tubes - 410S (12Cr) oraustenitic SS.

8. Reclaimer (steam in shell side). Tubes - austenitic SS.

9. Lean Amine Pump

a. Casing - CS, 1/4 inch CA, PWHT.

b. Trim - 316 SS, 12Cr or Ni-Resist.

10. Piping

a. All lines containing rich or lean (not fresh) aminesolutions shall be PWHT.

b. Lean Amine

(1) Below 200°F - CS, 1/8 inch CA, 13% Cr valvetrim.

(2) Above 200°F - CS, 3/16 inch CA, 316 SS valvetrim.

c. Rich Amine

(1) Below 200°F - CS, 3/16 inch CA, 13% Cr valvetrim.

(2) Above 200°F - CS, 3/16 inch CA, 316 SS valvetrim.



5.11 Sulfur Recovery Units

All of the major equipment on claus units, thermal reactors, waste heatboilers, condensers, and catalytic reactors is carbon steel. Hottervessels, such as waste heat boiler inlets and thermal reactors, arerefractory lined. Hot lines are either refractory lined or of austeniticstainless steel. Vapor reheat lines on the latest units have been 310 SS(25Cr-20Ni). Some intergranular cracking problems due to polythionicacid have occurred in vapor reheat lines that are exposed totemperatures above 850°F. There have been problems with the tubesheet -tube joints in waste heat boilers and refractory and vessel burnouts inthermal reactors. There have been problems with thermal reactortemperature measurement. Some plants have experienced burner problemswhen complex burner arrangements have been used. Simple austeniticstainless steel, open pipe arrangements have given at least 5 years ofservice.

5.12 Tail Gas Treating Units

Texaco has multi-year experience of treating SRU tail gas by hydrogenrich reducing gas. All of the major equipment of this part of the TGTU,namely feed heater, catalytic reactor, waste heat boiler, quench tower,booster blower, and knockout drum are carbon steel. Feed heater andcatalytic reactor are refractory lined.

Piping for sour water service is carbon steel with 0.25 inch corrosionallowance.

No corrosion problems at this unit have been reported so far.

The cooled gas with most sulfur reduced to H2S goes to absorber of MDEAsour gas treating process. Recommendations of the materials for thispart of the unit are given in Section 5.10.

5.13 References

1. “Corrosion in Petroleum Refining and Petrochemical Operations”,J.Gudzeit, R.D. Merrick, L.R. Scharfstein, ASM Metals Handbook,Ninth Edition, Volume 13, “Corrosion”, 1987.

2. “Materials Selection for Refineries and Associated Facilities”,R.A. White, E.F. Ehmke, NACE, 1991.

3. “Corrosion in the Oil Refining Industry”, NACE Conference, Houston,September 1996.



TABLE 1NOMINAL CHEMICAL COMPOSITION OF COMMONLY USED ALLOYS (WT %)

MATERIAL Fe Cr Ni Mo Cu Zn OTHER

Carbon Steel Base

Low Alloy Carbon-0.5Mo Base 0.5 1.25Cr-0.5Mo Base 1.25 0.5 2.25Cr-1Mo Base 2.25 1 5Cr-0.5Mo Base 5 0.5 9Cr-1Mo Base 9 1 AISI 4140 Base 1 0.25 0.4C AISI 4340 Base 1 2 0.25 0.4C 2.5 Nickel Base 2.5 3.5 Nickel Base 3.5

Chromium Stainless Steels Type 405 Base 13 0.3Al Type 410S Base 13 0.08C Max Type 410 Base 13 Type 430 Base 17 CA-15 Casting Base 13 1.0 Max 0.15C Max CA-6NM Casting Base 13 4 1 0.06C Max E-Brite XM-27 Base 26 1 0.1Cb; 0.01N; 0.01C Max

Cr-Ni Austenitic SS Type 304 Base 18 10 0.08C Max Type 304L Base 18 10 0.03C Max Type 316 Base 17 12 2.5 0.08C Max Type 316L Base 17 12 2.5 0.03C Max Type 321 Base 18 10 0.5Ti Type 347 Base 18 10 0.8Cb Type 317 Base 19 13 3.5 0.08C Max Type 317L Base 19 13 3.5 0.03C Max

Cr-Ni Ferritic-Austenitic SS 3RE60 Base 18.5 4.7 2.7 0.03C Max 2205 Base 22 5.5 3 0.03C Max; 0.14N 2507 Base 25 7 4 0.03C Max; 0.3N CD-4MCu (Casting) Base 26 5.5 2.0 0.04C Max; 3.0Cu

High Nickel Alloys Alloy Al-6XN Base 21 24.5 6.5 0.03C Max; 0.21N Alloy 20Cb-3 36 21 35 2.5 3.5 1.0Cb; 0.07C Max Incoloy 800 46 21 33 0.10C Max Incoloy 825 30 22 42 3 2 1.0Ti; 0.05C Max Inconel 600 8 16 76 0.15C Max Inconel 625 3 22 62 9 4.0Cb; 0.1C Max Hastelloy B 5 Base 30 0.05C Max Hastelloy C 276 5 15.5 Base 16 4.0W; 2.5Co; 0.01C Max Monel 2 68 30

Copper Alloys Admiralty 70 29 1.0Sn Aluminum Brass 77 21 2.0Al Naval Brass 60 39 1.0Sn Copper Nickel 90/10 1 10 89 Copper Nickel 70/30 1 30 69 Aluminum Bronze 2 91 7.0Al

Aluminum Alloys Alloy 3003 Al Base, Si(0.6), Fe(0.7), Mn(1.5), Co(0.2) Alclad 3003 Clad with 7072 Alloy: Al Base, Zn (1.3), Si+Fe(0.7)

Titanium Unalloyed TiTitanium Alloy Ti Base, Mo(0.3), Ni(0.8)

Corrosion/Heat Resistant Base 1-5.5 18-37 2.3-3.0CCast Iron Ni-Resist

Hardfacing Alloys Stellite 1 C(2.5), Cr(30), W(12), Co(55) 6 C(1), Cr(29), W(4), Co(66) Tapco 200X C(4), Fe Base, Cr-Mo Carbides 275 High C, Co Base, Cr-W Carbides



TABLE 2ASTM DESIGNATIONS OF COMMONLY USED ALLOYS

MATERIAL PLATE EXCHANGER TUBES PIPES CASTING FORGINGS

Carbon Steel A285 A179 A53 A216 A105A515 A214 A106 A181A516 A266

Low Alloy Carbon - 0.5Mo A204; A302B A209 A335 P1; A161 T1 A217 WC1 A182 F1 1.25Cr-0.5Mo A387 GR11 A199 T11; A213 T11 A200 T11; A335 P11 A217 WC6 A182 F11 2.25Cr-1Mo A387 GR22 A199 T22; A213 T22 A200 T22; A335 P22 A217 WC9 A182 F22 5Cr-0.5Mo A387 GR5 A199 T5; A213 T5 A200 T5; A335 P5 A217 C5 A182 F5 9Cr-1Mo A387 GR9 A199 T9; A213 T9 A200 T9; A335 P9 A217 C12 A182 F99 2.5 Nickel A203 GRB A334 GR7 A333 GR7 A352 LC2 3.5 Nickel A203 GRE A334 GR3 A333 GR3 A352 LC3

Chromium Stainless Steels Type 405 A240 A268 Type 410S A240 Type 410 A240 A268 A351 CA15 Type 430 A268 A182 F430 CA6NM A351 CA6NM E-Brite XM-27 A176 A268 A731

Cr-Ni Austenitic SS Type 304 A240 A213; A249; A271 A312 A351 CF8 A182 F304 Type 304L A240 A213; A249 A312 A351 CF3 A182 F304L Type 316 A240 A213; A249; A271 A312 A351 CF8M A182 F316 Type 316L A240 A213; A249 A312 A351 CF3M A182 F316L Type 317 A240 A213; A249 A312 A351 CG8M A182 F317 Type 317L A240 A213; A249 A312 A182 F317L Type 321 A240 A213; A249; A271 A312 A182 F321 Type 347 A240 A213; A249; A271 A312 A351 CF8C A182 F347

Cr-Ni Ferritic-Austenitic SS 3RE60 (S31500) A789 A790 2205 (S31803) A240 A789 A790 A182 F51 2507 (S32750) A789 A790 A182 F53 CD-4MCu A890

High Nickel Alloys Alloy Al-6XN B688 B690 B690

N08367 N08367 N08367 Alloy 20Cb-3 B463 B468 B464 A296 CN7M B462 Incoloy 800 B409 B163 B407

(Ni-Fe-Cr) Incoloy 825 B424 B163 B423

(Ni-Fe-Cr-Mo-Cu) Inconel 600 B168 B163 B167 A351 CY40

(Ni-Cr-Fe) Inconel 625 B443 B444 B444 Hastelloy B B333 A494 N12M Hastelloy C276 B575 (N10276) B622 B622 A494 CW12M Monel B127 B163 B165 A296 M35

(Ni-Cu)Copper Alloys Admiralty B111 C44300 Al Brass B111 C68700 Copper Nickel 90/10 B171 C70600 B111 C70600 B467 70/30 B171 C71500 B111 C71500 B467

C71640 Naval Brass B171 C46500 Al Bronze B169 B148 AL955

Aluminum Alloys Alloy 3003 B209 B234 Alclad 3003 B209 B234

Titanium B265 GR 1,2,3,7 B338 GR 1,2,3,7 B337 GR 1,2,3,7 B381Titanium Alloy B265 GR12 B338 GR12 B337 GR12 B381

Corrosion/Heat A439 Resistant CastIron Ni-Resist

























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Normas Texaco GEMS G-G-1 Material Selection Guide for Refinery Process Unit