corrosion resistan characteristics

8/22/2019 Corrosion Resistan Characteristics

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Note: The source of the technical material in this volume is the ProfessionalEngineering Development Program (PEDP) of Engineering Services.

Warning: The material contained in this document was developed for SaudiAramco and is intended for the exclusive use of Saudi Aramcos

employees. Any material contained in this document which is notalready in the public domain may not be copied, reproduced, sold, given,

or disclosed to third parties, or otherwise used in whole, or in part,

without the written permission of the Vice President, Engineering

Services, Saudi Aramco.

Chapter : Materials & Corrosion Control For additional information on this subject, contact

File Reference: COE10505 S.B. Jones on 874-1969 or S.P. Cox on 874-2488

Engineering EncyclopediaSaudi Aramco DeskTop Standards

Corrosion-Resistant Characteristics


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Engineering Encyclopedia Materials & Corrosion Control

Corrosion Resistant Characteristics

Saudi Aramco DeskTop Standards

CONTENTS PAGES

CORROSION RESISTANCE CHARACTERISTICS, DESIGN

PRACTICES, AND ANALYSIS METHODS ............................................................ 1

Uniform or General Corrosion ........................................................................ 1

Uniform Corrosion Allowance ........................................................................ 7

Estimated Remaining Life ............................................................................... 8

Nonuniform Corrosion .................................................................................. 10

Pitting Corrosion................................................................................ 11

Under-deposit Corrosion.................................................................... 12

Crevice Corrosion .............................................................................. 13

Galvanic Attack ................................................................................. 14

Intergranular Attack ........................................................................... 16

Dealloying.......................................................................................... 18

Stress-Related Corrosion.................................................................... 19

Stress Corrosion Cracking of Stainless Steels.................................... 21

Stress Cracking of Carbon and Low-Alloy Steels ............................. 26

Effect of Velocity on Corrosion......................................................... 28

EVALUATING TYPICAL DESIGN RELATED PROBLEMS............................... 31

CORROSION RESISTANCE STRATEGIES USED IN SAUDI

ARAMCO ................................................................................................................. 33

General Corrosion-Resistant Characteristics of Carbon Steel ....................... 33

Localized Corrosion-Resistant Characteristics of Carbon Steel .................... 34

General Corrosion-Resistant Characteristics of Stainless Steel ..................... 34

Localized Corrosion-Resistant Characteristics of Stainless Steel............. ..... 35


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Saudi Aramco DeskTop Standards

General and Localized Corrosion-Resistant Characteristics of

Other Commonly Used Materials.................................................................. 36

Nickel-Base Alloys ............................................................................ 36

Copper-Base Alloys ........................................................................... 36

Titanium............................................................................................. 37


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Saudi Aramco DeskTop Standards 1

Corrosion Resistance Characteristics, Design Practices, and Analysis

Methods

Corrosion is defined as a deterioration of a material (usually a metal) or its properties due toexposure to an environment. The type of corrosion damage and deterioration that occurs in a

particular material will depend upon its environment. The corrosion resistance of a metal or

alloy is extremely important and must be considered when selecting materials of construction

to prevent or minimize corrosion in service.

It is necessary to recognize and understand the various types of corrosion that can occur. The

important features, susceptible materials, and typical environments for uniform and

nonuniform corrosion are summarized below.

Uniform or General Corrosion

When the entire surface of a metal or alloy corrodes at about the same rate in a particular

environment, the corrosion is termed general or uniform corrosion. Examination of a crosssection of the corroded material would reveal relatively uniform thinning, shown in Figure 1.

Figure 1. Cross Section of a Material Subject to Uniform

Corrosion


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Carbon and low-alloy steels can suffer general corrosion during service due to their inherent

lack of corrosion resistance. Certain environments found in refineries, petrochemical plants,

and/or production facilities promote corrosion of carbon and low-alloy steels. Some of the

common environments are: Hydrocarbons containing wet hydrogen sulfide (sour service)

Hydrocarbon gas streams containing wet hydrogen sulfide + carbon dioxide

Sour water (process water containing hydrogen sulfide)

Steam condensate containing dissolved carbon dioxide

Hot sulfur-bearing hydrocarbons

Amine-hydrogen sulfide-carbon dioxide solutions

Brines

Industrial atmosphere

High temperature oxidation (furnace tubes).

While this list is not all-inclusive, it does include the environments that are responsible for

much of the corrosion of carbon and low-alloy steel equipment in a refinery, petrochemical

plant, or production facility.

Industrial atmospheres promote external corrosion of carbon and low-alloy steels. Corrosion

rates are usually low, 0.025-0.050 mm/yr (1-2 mils/yr), but some atmospheres, especiallythose containing acid vapors, can be very corrosive. Figure 2 illustrates weight loss data

versus time for corrosion test samples exposed at three locations. Two locations, the Martinez

Refinery and the Geysers in California, represent industrial locations, while the University of

California at Davis is a nonindustrial, residential location. The data in Figure 2 illustrate that

the weight loss (which can be converted to corrosion rate) experienced by the samples due to

atmospheric corrosion in a residential location is much less than that in an industrial location.

In addition, after about three years, the weight loss experienced by the samples exposed to the

Geysers surpasses that of the samples located in the refinery. This is because the atmosphere

around the Geyers contains sulfur dioxide and sulfur trioxide which form sulfurous and

sulfuric acids when exposed to the water vapor in the atmosphere.


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Note the Corrosion at the Refinery, about 1.1 mpy for Carbon Steel.

Figure 2. Atmospheric Corrosion Test Data.


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Figure 3 illustrates isocorrosion lines (lines of constant corrosion rate) for carbon-steel

material exposed to aqueous solutions containing various concentrations of H2S, NH3, and

HCl up to 500 ppm each.

Figure 3. Acid Corrosion: Isocorrosion Lines for Carbon Steelin a Solution of HCL-H2 S-NH3 Each Totaling 500

ppm.

Several important concepts apparent from this diagram are:

The corrosion rate of carbon steel decreases as the NH3 concentration is

increased, and the HCl and H2S concentrations are decreased.

The corrosion rate of carbon steel increases as the concentration of either H2S

or HCl is increased.

These observations are expected, since carbon and low-alloy steels corrode at much higher

rates in acids, such as HCl or H2S, than in bases, such as NH3. In some process units, such asthe overhead system of crude units, compounds based on NH3 are added to process streams to

inhibit corrosion in carbon and low-alloy steels.


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Carbon and low-alloy steels are very susceptible to oxidation at high temperatures and

consequently are seldom used for components such as furnace tubes or tube supports. Figure

4 may be used to select an alloy for high temperature applications. For the temperature range

covered by Figure 4, Type 310 Stainless Steel, Incoloy or Inconel alloys are required toprovide satisfactory oxidation resistance.

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

1516

1718

19

20

25

300.02

0.03

0.05

0.1

0.2

0.5

0.7

1.0

1.5

2.0

4.0

10.0

20.0

12

Rfere

nce

Lin

e

%C

hromiumi

nthealloy

TemperatureF

Excessive

Moderate

Satisfactory

Corros

ionrate,

in./year

% Nickel in the alloy

1600

1700

1800

1900

2000

0

510

1520

25

30

35

40

45

50

6070

Figure 4. High-Temperature Oxidation of FE-Cr-Ni Alloys.


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The vast majority of equipment and piping in a refinery is fabricated from carbon steel and

low-alloy steels such as 5 Cr- Mo and 9 Cr-1 Mo. However, these materials are susceptible to

sulfidation corrosion when exposed to hot sulfur-bearing hydrocarbons. The sulfidation rate

depends upon the sulfur content of the hydrocarbon and the temperature. In general, thesulfidation rate increases as the temperature or sulfur content is increased. Figure 5 illustrates

the sulfidation rates of carbon steel, 5 Cr- Mo, 9 Cr-1 Mo, and stainless steel as a function of

temperature in an oil containing 0.60 wt-% sulfur.

Figure 5. Sulfidation Rates of Carbon Steel, 5Cr1/2Mo Steel,

9Cr 1Mo Steel

and 18Cr 8Ni Stainless Steel.


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As can be seen from the curves, the sulfidation rate of carbon steel becomes rather high above

about 288 C (550 F) and reaches a maximum rate at about 371 C (700 F) before dropping.

A similar peak is exhibited by the other materials. Sulfidation rates exhibit a drastic decrease

at high temperatures above about 427 C (800 F), because the hydrocarbon decomposes andforms a protective layer of coke on equipment surfaces. In practice, carbon steel is seldom

used in sulfur-bearing environments at temperatures above 288 C (550 F). Under these

conditions, 5Cr and 9Cr materials are normally used.

When a material corrodes by general, uniform corrosion, the corrosion rate may be

determined by ultrasonic thickness measurements, or by using corrosion coupons. Corrosion

coupons are made to standard dimensions (to ensure a known surface area) and are weighed

before and after exposure to the corrosive environment. The coupon should be exposed for

30-60 days to obtain meaningful data and cleaned after exposure to remove corrosion

products and scale. It is important to realize that corrosion coupons may not accurately

represent the conditions along a vessel or heat exchanger wall. Consequently, the corrosion

rate obtained from the coupon may be somewhat different than the actual corrosion rate.However, if the coupons are located properly, they are certainly capable of indicating

significant changes in corrosion rate. Increases or decreases in corrosion rate are usually due

to changes in the process or operating conditions or to frequent upsets within the system, such

as temperature excursions.

The corrosion rate in mils per year (MPY) is determined as follows:

Cor. Rate (MPY) =

Original Weight Final Weight ( milligrams )

Area (SQ DM ) Days is Service

1.437

Density

To relate inches per year (IPY) to MPY, multiply IPY by 1000.

It is also useful to visually examine the corrosion coupon before and after cleaning, to observe

the appearance of the corrosion product or scale and the appearance of the corroded corrosioncoupon.

Uniform Corrosion Allowance

A common petroleum industry practice is to design new equipment able to safely undergo

uniform corrosion by providing a greater thickness than that required for pressure,

temperature, head of liquid, wind load, etc. The greater thickness or corrosion allowance is

based upon the expected corrosion rate (mpy) in the particular service and the design life of

the equipment or unit. For example, the predicted corrosion rate for a new carbon-steel

product cooler is 6 mpy, and the unit design life is 15 years. The required corrosion

allowance is 6 mpy x 15 years = 90 mils (0.090 in). The usual approach is to provide a 3.2

mm (1/8 in) minimum corrosion allowance. If the corrosion rate is somewhat higher (say 8mpy), the fifteen year life can still be attained. If the uniform corrosion rate remains at around

6 mpy, the actual service life may be safely and economically extended.


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It is important to note that corrosion allowance must be based on the predicted or measured

corrosion rate for the particular service and expected operating temperature. In some cases,

changes in operating temperature (higher or lower), liquid/vapor phase changes, and increases

in velocity may significantly increase corrosion rate and reduce service life. Depending onthe required service life of the equipment or unit, replacement in kind, replacement with an

increase in corrosion allowance, or replacement with a more corrosion-resistant material or

alloy may be required.

Estimated Remaining Life

As corrosion occurs on the equipment, the wall thickness and corrosion allowance are

reduced. It is necessary to periodically measure the wall thickness to determine the remaining

corrosion allowance and to estimate the remaining service life.

The estimated remaining life can be determined as follows:

Estimated remaining life (years) =

Remaining Corrosion Allowance (mpy )

Current Corrosion Rate (mpy / yr)

A practical example of this approach would be a fire, causing an unscheduled shutdown of an

atmospheric crude tower. Figure 6 shows the range of thickness readings, 3.6 mm (0.14 in)

and greater, obtained from an ultrasonic survey on a 760 mm (30 in) diameter carbon steel

overhead line. The minimum required thickness (T min.) is 2.5 mm (0.100 in). Based on the

last two inspections, the current corrosion rate is approximately 45 mils/yr. The next

scheduled shutdown for the crude unit will be in 2 years. To decide on necessary repairs, the

estimated remaining life approach can be used:

Estimated remaining life=

Remaining Corrosion Allowance

Current Corrosion Rate

2 years = Remaining Corrosion Allowance

45 mpy

90 mils (.090 in) = Remaining Corrosion Allowance T (min.)

+ Corrosion Allowance (CA) = Required Thickness

Where: T (min.) = 0.10 in (2.5 mm), CA = 0.090 in (2.3 mm); the Required Remaining

Thickness = 0.10 in + 0.090 in = 0.19 in (4.8 mm)


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On this basis, it was decided to install external bands or reinforcing plates on all areas 5.2 mm

(0.20 in) or less in thickness. After the completion of the repairs, the unit was restarted.

Figure 6. Ultrasonic Thickness Survey

on Atmospheric tower Overhead Line


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Nonuniform Corrosion

Nonuniform or localized corrosion occurs at what appear to be small, randomly selected sites

on the surface of the material. Only a small percentage of the total surface, for example less

than 3%, may be actively corroding. Local corrosion manifests itself as pitting, crevice

corrosion, under-deposit corrosion, or stress corrosion cracking. In some situations, only

pitting corrosion may occur, as illustrated schematically in Figure 7a. In other environments,

general corrosion as well as local pitting corrosion might occur. This is illustrated

schematically in Figure 7b.

Figure 7a. Pitting Corrosion Can Leave Some

of the Original Surface Unattacked.

Figure 7b. Other Forms of Pitting Are Combined

with Generalized Corrosion

Pitting, under-deposit corrosion, and cracks due to stress corrosion cracking are often found

by visual examination of the material surface. However, some cracks caused by stress

corrosion are extremely fine and might be missed during visual examination. To remedy this

situation, the surfaces of non-magnetic materials are liquid penetrant (PT) inspected, and the

surfaces of magnetic materials (carbon and low-alloy steels) are inspected using magnetic

particle (MT) or wet fluorescent magnetic particle (WFMT). Other inspection techniques,

such as radiography and ultrasonic testing, are also used to detect cracks.

Depending upon the specific environment, nonuniform or localized corrosion such as pitting,

crevice corrosion, and under-deposit corrosion has been experienced at Saudi-Aramco

facilities when using high-alloy materials like the 300 series austentitic stainless steels.However, nickel-base alloys like Incoloy and Inconel can also exhibit pitting and under-

deposit corrosion in higher-temperature, low pH chloride-bearing aqueous environments. A

good example of localized corrosion is the pitting of austenitic stainless steels in seawater.


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Pitting Corrosion

In pitting corrosion, the small diameter holes or depressions that form on the materials

surface during service are called pits. Pits usually form because of the presence of small

surface discontinuities that might include microscopic inclusions, machining marks, small

scratches, or dents. Although a pit may be extremely small when it first forms, it can grow

until a through-wall failure occurs if the environment is sufficiently aggressive.

An example of pitting-induced failure can been seen in the use of the 300 series austenitic

stainless steels in salt or brackish water. These materials will perform satisfactorily if the

component is crevice free and if the water is maintained at a velocity of about 5 ft/sec.

Sufficient fluid flow is required to maintain the passivity (adherent corrosion film) of the

stainless steel surface. However, if the equipment is shut down and not drained, or contains

crevices or stagnant dead-legged areas, chloride-induced pitting is likely. It is important to

understand that once pitting begins in a stagnant, low-flow area, it is very difficult, if not

impossible, to stop. The pits grow rapidly, and the material fails via through-wall perforationin a relatively short period of time. Under severe pitting conditions, failures in stainless steel

equipment in sea or brackish water service have been known to occur in six months or less.

Because of the problems associated with pitting corrosion in chloride-bearing media, such as

sea and brackish waters, the 300 series stainless steels are seldom specified for these services.

To avoid pitting problems under these conditions a duplex alloy, such as Zeron 100, or

austenitic alloys such as 904L, Avesta 254SMO, Inconel 625, or Hastelloy C276 must be

used. These alloys contain more molybdenum than the 300 series stainless steels and are more

resistant to pitting. Nonferrous materials such as Titanium are also suitable for sea and

brackish water service.


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Under-deposit Corrosion

Dirt, solids, loose (non-adherent) corrosion products, or salts present in process streams can

cause severe corrosion of exchanger tubes (internal or external) and piping. Figure 8 shows

external under-deposit attack on a condenser tube.

Figure 8. Under-Deposit Attack on Outside of a Condenser

Tube.

Note the Perforation in the Tube Wall.

The damage to the tube occurred as a result of oxygen concentration cell attack. During

service the oxygen present in the cooling water continually repaired and maintained the

protective film on the surface of the clean tube, giving the tube its corrosion resistance.

However, when deposits formed on the tube, the oxygen in the water could no longer reachthe tube surface to repair and maintain the protective film. Consequently, areas beneath the

deposits were highly susceptible to corrosive attack, while the deposit-free surfaces were

protected. This created a galvanic cell in which the material beneath the deposits corroded in

preference to the deposit-free surfaces. The corrosion rate associated with under-deposit

attack can be very high and the resulting damage severe, as illustrated in this figure.

Another example of under-deposit corrosion is corrosion that occurs in carbon-steel tubing in

condensers or air coolers in Hydrotreating or Hydrocracking Units. The corrosion is caused

by H2S and NH3 which are formed during the hydrotreating process from the sulfur and

nitrogen in the crude oil. Liquid hydrocarbons, solid NH4HS, and NH4Cl salts are formed

when the effluent from the reactor is condensed. The solid ammonium salts are deposited on

the tube ID surfaces. At temperatures below the dew point in the presence of moisture severeacidic corrosion of the tube material occurred beneath the deposits. The corrosion was due to

the formation of HCl. This problem was solved by replacing the carbon-steel tubes with high-

alloy tubes manufactured from Incoloy 800 or Incoloy 825. Another mitigation method would

have been to utilize water washing to dissolve the deposits.


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Crevice Corrosion

It is important to eliminate crevices whenever possible when designing and fabricating

equipment. When this is not possible, the crevice areas may be sealed with a continuous fillet

weld or filled with a protective coating or sealer. Crevices that are not sealed are susceptible

to accelerated corrosion. The mechanism is essentially identical to that described above for

under-deposit corrosion. In stainless steel equipment exposed to chloride-bearing media, this

problem is especially severe because the stagnant crevice conditions result in a corrosion

mechanism that is similar to pitting. Recall that pitting corrosion occurs at very high rates, and

through-wall failures can occur within months. Figure 9 illustrates the type of damage

associated with crevice corrosion.

Figure 9. Corrosion at a Crevice Formed between a Metal

Coupon

and an Insulating Washer in a Test Spool


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Galvanic Attack

Galvanic attack occurs when dissimilar metals are brought into intimate contact with one

another in an electrolyte. The more active metal called the anode corrodes, while the noble

metal (i.e., platinum, iridium, osmium, palladium, rhodium, ruthenium, silver, gold) called

the cathode does not. For certain environments, it is important to understand that the corrosion

rate of a particular metal increases dramatically when it is brought into contact with a more

noble metal. In other words, the more noble metal causes an increase in the corrosion rate of

the more active metal.

Figure 10 shows a schematic example of galvanic attack.

Figure 10. Galvanic Attack

The table in Figure 11 lists the galvanic series of various metals and alloys in seawater.

MagnesiumZinc

CadmiumAluminumAntimonyTungstenLeadTinNickelCopper

0.00.4

0.49.8

153.1176.0183.2171.1181.1183.1

3104.3688.0

307.9105.9

13.85.23.62.50.20.0

Corrosion (iron)mg

Corrosion(second metal)

mg

Second Metal

Figure 11. Table Gives Corrosion Results for

Plates of Iron and a Second Metal,Coupled Galvanically and Totally Immersed in a 1%

Sodium Chloride Solution.


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In a galvanic series, the materials are listed in descending order of activity, with the most

active metal listed first and the least active metal listed last. Materials are also grouped in

families. For example, the copper alloys (brasses, bronzes and copper-nickels) and 300 series

stainless steels form two distinct families. Pairings of metals from the same general family, forexample Red Brass and Admiralty Brass or Type 304 stainless steel and Alloy 20Cb3, will not

result in excessive attack of either metal due to galvanic corrosion. However, pairings of

metals from outside their respective families can result in excessive corrosion of the more

active metal. For example, a very severe galvanic cell is created when aluminum, which is

very inert, is coupled with carbon steel, which is relatively active. The aluminum corrodes at a

rate that is unacceptably high for engineering purposes.

Galvanic considerations are particularly important in cooling water and other services

involving aqueous phases. It is very important in heat exchangers that the tube material be

more noble than the tubesheet to prevent premature failure of the tubes. For example, it is

appropriate to use noble stainless steel tubes in a carbon steel tubesheet. The thick tubesheet,

being the active member of the couple, can tolerate a relatively high corrosion rate for a longperiod of time. However, if the tubes were steel and the tubesheet stainless steel, the thin

carbon steel tubes would perforate quickly, resulting in a reduced service life for the

exchanger tubing.

Another important factor to consider in assessing galvanic attack is the ratio of anode-to-

cathode area, sometimes referred to as the area effect. The galvanic effects on the anodic

material will be minimal if the surface area of the anodic material is larger than the surface

area of the cathodic material. However, if the cathodic area is larger than the anodic area, the

galvanic corrosion will be extremely severe.

A good example of the area effect occurred when a carbon steel plug was inadvertently

installed in a Monel channel in brackish cooling water service. The plug rapidly corroded and

the exchanger leaked.

Galvanic corrosion can be minimized by using similar materials or materials from the same

family, i.e., avoiding dissimilar metal couples, electrically isolating connections involving

dissimilar metals, and providing sacrificial anodes to protect the anodic material. An example

of the use of sacrificial anodes is the installation of magnesium anodes in cooling water

exchangers to protect the carbon-steel channels. Depending on water quality, it is often

necessary to use copper-nickel or brass materials for tubes and tubesheets to obtain

satisfactory tube bundle life. Carbon-steel channels are specified to minimize costs.

Magnesium anodes are installed on the channel ID to minimize galvanic corrosion of the

carbon-steel channel in the area immediately adjacent to the copper-nickel or brass tubesheet.


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Intergranular Attack

Heat treatment or welding of alloys can result in changes in the microstructure of the material.

A good example of this phenomenon is the sensitization of the 300 series stainless steels

during welding.

Sensitization is caused by the heat of welding and results in the formation of chromium

carbide in the grain boundaries of the heat-affected material adjacent to the weld nugget.

Carbide formation depletes the metal immediately adjacent to the grain boundaries of

chromium on a microscopic scale. This loss of chromium results in a very narrow band of

material on both sides of the grain boundary which no longer has the corrosion resistance of

the bulk stainless steel. In certain aqueous, corrosive media, a galvanic cell develops between

the chromium depleted zone and the chromium-rich, bulk material. In this cell the chromium

depleted area is the anode, and corrodes preferentially to the cathodic bulk material. The

corrosion proceeds along the grain boundaries and is sometimes referred to as weld decay.

Environments that promote weld decay (intergranular corrosion) in the 300 series austeniticstainless steels include wet sour crude oil, sodium hypochlorite, sulfuric acid, nitric acid, and

sulfurous acid (SO2 + H2O). This is by no means a complete list.

Figure 12A. Schematic Depiction of Intergranular Attack

in the Heat Affected Zone.


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Figure 12B. Macrophotograph of Weld

Showing This Form of Attack.

Welding is not the only process that promotes sensitization of austenitic stainless steel.

Postweld heat treatment (PWHT) can also result in sensitization. It is important to note that

after PWHT the entire component, not just the weld areas, may be susceptible to intergranular

corrosion. Stainless steels are almost never given conventional PWHT for this reason.

In certain environments, particularly if the stainless steel material is under a high degree of

stress, cracks can initiate at the root of the intergranular corrosion. This type of cracking is

known as intergranular stress corrosion cracking. In the absence of cracking, the intergranular

stress corrosion process proceeds until through-wall penetration occurs.

Intergranular corrosion of weld heat-affected material in the 300 series austenitic stainless

steels can be controlled by using L grade (low carbon content) material and limiting the

heat input during welding. It is recommended that Saudi Aramco Specifications andMaterials/Welding Engineers be consulted.


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Dealloying

Dealloying the environment selectively removes one of the alloy components from a material.

Copper-base alloys may be attacked by:

Dezincification-removal of zinc from brass

Dealuminification-removal of aluminum from aluminum brasses and

bronzes

Denickelification-removal of nickel from cupronickels and Monel.

Figure 13 shows a schematic illustration of layer and plug-type dezincification and a

photomicrograph of plug-type dezincification of brass.

Figure 13. Photomicrograph of Plug Type Dezincification of

Brass.

This type of attack is not very common in todays facilities, since brasses are no longer widely

used.

Graphitization of cast iron occurs when the iron is selectively removed and only carbon

(graphite) is left. This can occur in cooling water piping. Since this type of attack occurs over

a long period of time, the usual solution is to replace the cast iron pipe in kind.


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Stress-Related Corrosion

Stress corrosion cracking, also termed environmental cracking, is defined as a cracking

process caused by the combined effects of tensile stress and environment on a specific

material. There are several types of stress corrosion cracking. It is important to understand the

fundamentals of each type, and the materials that are least/most susceptible.

In general, for stress or environmental cracking to occur, the material must be susceptible to

corrosion in the particular environment, must be under tensile stress, and must be exposed to

this environment for a sufficient period of time. Cracking usually occurs at right angles to the

principal direction of the stress, and can be transgranular or intergranular, depending on the

mechanism of the stress corrosion. For example, chloride stress corrosion cracking (SCC) of

austenitic stainless steels is usually transgranular, while polythionic acid stress cracking is

intergranular. The cracking is usually highly branched, but may consist of only one major

crack. The stresses required to induce stress corrosion cracking need only be static (tensile).

Figure 14A schematically illustrates stress corrosion cracking.

Figure 14a. Stress Corrosion Cracking

Corrosion fatigue requires cyclical stresses, i.e., dynamic loading to induce cracking. It is

important to understand that under cyclical stress conditions the corrosive environmentreduces the fatigue resistance of the material. A very aggressive environment can affect crack

initiation, crack propagation, or both. The cracks often initiate at pits or intergranular

corrosion sites. They can be either intergranular or transgranular. Corrosion products often

cause a wedge-opening action, and straight singular cracks with little branching are observed.

Corrosion fatigue is most pronounced under low cyclic, high stress conditions. High cycle

fatigue is relatively unaffected by corrosion, unless the material is severely pitted. In severely

pitted material, cracks can initiate at pits.


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A schematic illustrating corrosion fatigue is shown in Figure 14B.

Figure 14b. Corrosion Fatigue

Corrosion fatigue can be mitigated by minimizing the corrosivity of the environment. Refer to

Figure 15.

Figure 15. Effect of Alternating Stresses with and without

Corrosion.


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Stress Corrosion Cracking of Stainless Steels

The most common form of stress corrosion cracking (SCC) is undoubtedly chloride SCC of

300 series austenitic stainless steels, such as Type 304 SS, Type 316 SS, etc.

Several conditions are required for cracking to occur. These are:

The environment must contain aqueous chlorides.

Temperature must be above 60 C (140 F).

The material must be under stress.

The material must be exposed for a sufficient period of time.

For materials exposed to acidic chloride bearing solutions, chloride SCC can occur at lower

temperatures. It is also important to realize that tensile stress must be present for cracking to

occur.Figure 16 shows a photomicrograph of chloride SCC of austenitic stainless steel.

Figure 16. Stress Corrosion Cracking in Austenitic Stainless

Steel


25/41




The presence of dissolved oxygen and acidic components in the environment usually

accelerates the time to failure. This form of cracking occurs in aqueous chloride-bearing

environments such as brackish water or seawater. However, it can occur in any chloride-

bearing environment such as wet crude oil, produced water from a production facility orGOSP, fresh water used for cooling, boiler feedwater, process water, steam condensate, etc.

Cracks are usually transgranular and highly branched.

It is important to determine if chlorides are present whenever specifying or considering the

use of the 300 series austenitic stainless steels in aqueous environments. If chlorides are

present, and the temperature is above 60 C (140 F), it is probably advisable to use a duplex

stainless steel or an austenitic stainless steel that has a high nickel content, such as Alloy

20Cb3, Incoloy 825, or Alloy 904L. Consult Saudi Aramco Specifications and the Materials

Engineering & Corrosion Control Department.

As shown in Figure 17, nickel content is an important factor in the prevention of SCC in

austenitic stainless steels.

Figure 17. The Effect of Nickel Content on SCC of Austenitic

Materials.


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Figure 18 shows the results of a survey on chloride SCC (136 cases in 109 locations). It is

important to note that some failures occurred at or below 1 ppm chlorides.

Figure 18. Chloride SCC of Austenitic Stainless SteelsMTI

Survey Data


27/41




As shown in Figure 19, chlorides and oxygen can have a synergistic effect on SCC of 304

stainless steel.

304SCC - All Heat Treatments SCC No SCC

SCC

Sensitized

Only

Tentative

SCC - Safe Area

1000

1001010.1

0.01

0.0010.01

0.1

100

1,000 10,000

Sensitized

Annealed

10

1

250 - 300 C

DissolvedO,

g/m

(ppm)

2

CI Concentration, g/m (ppm)3

Figure 19. Synergistic Effect of Chlorides and Oxygen

on the SCC of Type 304 Stainless Steel.

Environments such as polythionic acid promote intergranular stress corrosion cracking of

sensitized austenitic stainless steels, such as Type 304 and Type 316. Cracking can occur in

the weld area or in the base metal, and is caused by sensitization due to long-term elevated

temperature service. This type of stress cracking is an important consideration in

hydrocracking and hydrotreating units. It should be noted that equipment items in these units

are fabricated from Cr-Mo steel internally clad with stainless steel. Cracking does not occur

during operation, but occurs when the units are shutdown and opened to the atmosphere for

inspection or maintenance. The polythionic acid forms when the sulfide scale on the internal

stainless steel surfaces is exposed to oxygen and moisture from the air. Intergranular cracking

occurs in a relatively short period of time if the cladding material or the welds in the cladding

material is sensitized and contains sufficient residual stress.


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Polythionic acid stress corrosion cracking is mitigated by using the stabilized grades of

stainless steel for cladding (Type 321 or Type 347). The low carbon L grades, such as Type

304 L stainless steel are not recommended, since these materials suffer sensitization after

long-term elevated temperature service. However, it should be pointed out that even Types321 or 347 will eventually sensitize. To minimize the risk of cracking, equipment items in

Hydrotreating or Hydrocracking Units are rinsed with a basic solution prior to opening the

equipment to the environment. The basic residue will neutralize the polythionic acids as they

form.

Figure 20 illustrates the microstructure of unsensitized and sensitized austenitic stainless steel.

The left photo shows the desired microstructure with the carbides dispersed throughout the

grains. The right photo shows a sensitized structure. Note that carbides have formed in the

grain boundaries. The adjacent areas have substantially lower chromium content. This can

lead to intergranular attack of the sensitized stainless steel as shown in Figure 21, or to

intergranular stress corrosion cracking.

Figure 20 . Unsensitized and Sensitized Austenitic Stainless

Figure 21. Intergranular Attack of Sensitized Stainless


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Stress Cracking of Carbon and Low-Alloy Steels

Carbon and low-alloy steels in wet H2S service are susceptible to sulfide stress corrosion

cracking. Cracking usually occurs in the weld heat-affected zone of welds which have not

been stress relieved, especially if the material exhibits excessive hardness. The cracking is

usually transgranular, but can be intergranular. In general, carbon steels that exhibit hardness

values in excess of 22 Rockwell C are very susceptible to sulfide stress corrosion cracking at

ambient temperature. To minimize the risk of sulfide stress cracking in sour service, materials

of construction should comply with the requirements contained in NACE MR-01-75.

The figure on page 5 of the Appendix shows transverse cracking in the weld metal of a

pressure vessel main seam weld. (Source: Reference No. 1, NACE Corrosion paper)

Note the range in Brinell hardness. This sulfide stress crack originated in the hard outside pass

and terminated in the soft previous passes.

The risk of sulfide stress corrosion cracking can be minimized by exercising several

precautions. It is recommended that the requirements contained in NACE Standard MR-01-75 be followed when considering materials of construction for equipment in wet H2S service

in refining and production facilities. It is also recommended that the equipment be given

PWHT to reduce residual stresses and lower weld hardness.

Carbon and low-alloy steels are also susceptible to cracking due to caustic embrittlement. This

form of cracking has occurred in boilers and in equipment handling high temperature caustic.

Cracking usually occurs in the weld heat affected zone of welds which have not been stress

relieved, or in adjacent base metal that is under a high degree of residual stress. It is

recommended that equipment be given PWHT to reduce residual stresses and reduce weld

hardness to minimize the risk of cracking.


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As shown in Figure 21, caustic-embrittlement cracking of carbon steel is highly branched.

The examples that have been reviewed above represent only a few of the important

environment/material combinations that are known to cause stress corrosion cracking in

refining and production facilities. The table in Figure 22 lists the most common types of stresscorrosion cracking and the corresponding susceptible materials. It should be noted that this is

not a complete list.

CLASSIFICATIONS OF STRESS CORROSION FORMS

TYPES OF STRESSCORROSION CRACKING ALLOY FAMILY

Chloride

Polythionic Acid

Caustic

Wet H S

Amines

Hydrogen

Ammonia

Austenitic stainless steel

Austenitic stainless steel (sensitized)

Carbon Steel

Carbon Steel

Carbon Steel

Carbon and low alloy steels

Copper base alloys

2

Figure 22. Classifications of Stress Corrosion Forms


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Effect of Velocity on Corrosion

In piping and heat exchanger tubes the appearance of the corroded surface may be related to

the fluid flow. For example, when preferential wall thinning occurs at an elbow or a return

bend, it indicates that the components are suffering local erosion or erosion/corrosion due to

changes in the fluid flow direction. The corrosion mechanism is also likely to be

erosion/corrosion when pits become elongated in the direction of the flow and have a groove-

like appearance. In erosion/corrosion, the corrosion product, which in some situations is

protective, is continually removed from the material surface as a result of excessive velocity

or the action of abrasive particles in the fluid. This results in very high metal loss, as a

protective layer of corrosion product is never formed.

Figure 23 illustrates erosion/corrosion on a tube ID surface.

Figure 23. Tube Showing Cross Section of Impingement Pits.


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It is important to recognize the effects of velocity on corrosion rate when designing piping

systems or heat exchangers. Figure 24 indicates the effect of velocity on the corrosion rate of

various materials in seawater.

Figure 24. Metal Loss and Pitting Behavior as a Function of

Velocity

for Several Materials in Stagnant and Flowing

Seawater.

It is also important that the velocity limits indicated for piping and condenser design be

followed. If the recommended velocities are exceeded, the service life of the equipment or

piping is likely to be reduced. It is important to recognize that for some alloys, such as brassor copper/nickel, relatively small increases is fluid velocity can drastically increase the metal

loss. These materials are relatively soft and have inherently poor erosion resistance. (Erosion

is not a corrosion mechanism.)

Impellers in pumps can suffer from cavitation damage, a form of erosion, due to a lack of net

positive suction head during operation. Under these conditions bubbles form and collapse on

the material. This hammering effect results in spongy cavities.


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Figure 25 shows a schematic representation of cavitation erosion.

Figure 25. Schematic representation of cavitation.

Erosion problems are most often solved by modifying equipment and plant design. A larger

pipe size can be installed to reduce velocity. Filtration equipment can be installed to remove

abrasive particles. If none of these options are possible, components can be overlaid withhardfacing alloys or a more erosion-resistant material can be used.


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EVALUATing Typical Design Related Problems

NACE International has published the Corrosion Data Survey, Metals Section, Sixth Edition

(available in hard copy or survey computer software). The Survey contains extensive

information on uniform corrosion rates, pitting, stress corrosion cracking, intergranular attack,

and crevice attack. It is extensively used as a guide for materials selection. The information

was originally developed by Shell Development Company Engineers. NACE periodically

updates and publishes the Survey.

Refer to the Corrosion Data Survey, Metals Section, Sixth Edition, and the Errata dated

October 1985. The Matrix Key and Key to Data Points can be found on page 6 of the

Appendix (Source: Reference No. 2 NACE Corrosion Data Survey, matrix section). As the

Matrix Key explains, the vertical grid relates to temperature in F and C, the horizontal grid

relates to percent concentration in water. The Key to Data points explains that the symbols

used to indicate average penetration rate per year are: o < 2 mpy, o < 20 mpy, [] 20-50 mpy,

and x > 50 mpy.Note: As shown in the Erratum the last column should be m not mm. Throughout the book

corrosion rate data points are arranged on the grid for various services (in NACE alphabetical

order) and for various materials (steel, cast iron, stainless steel, copper base, nickel base, and

other metals and alloys). In addition to the data points reporting average penetration rate,

footnotes cover pitting, stress corrosion cracking, intergranular attack, and crevice attack. In

the absence of previous service information, the Corrosion Data Survey may be used to screen

the suitability of various materials for a field trial or corrosion testing.

Several examples that illustrate the use of the NACE Corrosion Data Survey for metals are

presented below.

Pages 7 and 8 of the Appendix show the information on pages 10 and 11 of the Survey.

Using the information on ammonium chloride, 6, the following can be noted: High corrosion rates: > 50 mpy on steel, 12Cr, 17Cr, and 304 SS at certain

concentrations and temperatures.

Both 304 and 316 SS are subject to pitting and stress corrosion cracking

(footnotes 1, 2).

Low Corrosion rates: < 2 mpy on several nickel-base alloys, tantalum, titanium,

and zirconium.

Pages 9 and 10 of the Appendix show the information on pages 118 and 119 of the Survey.


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Using the information on sodium hydroxide 2, the following information can be obtained:

Carbon steel can be used at lower temperatures and concentrations with

corrosion rates < 20 mpy.

The corrosion resistance of Type 316 SS is significantly better than Type 304

SS below 93 C (200 F).

The nickel-base alloys show low corrosion rates for a wide range of

concentrations and temperatures.

Page 11 of the Appendix shows the Caustic Soda Service Graph on page 176 of the Survey.

This graph is widely used as a reference to determine when stress relief of carbon steel welds

and bends is necessary, or when nickel alloys are required:

Area A: no stress relief required

Area B: stress relief of carbon steel welds and bends required

Area C: nickel alloys should be considered.

It is important to remember that equipment temperatures may be higher than normal operating

temperatures due to:

External steam tracing

Steam out or wash out with hot water during shutdowns

Upsets in temperature or pressure during operation.

There have been extensive industry reports of caustic cracking of pressure vessels and piping

attributed to these higher temperatures.

Pages 12 and 13 of the Appendix show the Sulfuric Acid Service Graph and Code For

Sulfuric Acid Graph, which are found on pages 184 and 185 of the Survey. This is a useful

reference to quickly determine the suitability of various materials (reported corrosion rate

corrosion resistan characteristics

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