Corrosion Resistan Characteristics

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Corrosion-Resistant Characteristics

Note: The source of the technical material in this volume is the Professional Engineering Development Program (PEDP) of Engineering Services. Warning: The material contained in this document was developed for Saudi Aramco and is intended for the exclusive use of Saudi Aramco’s employees. Any material contained in this document which is not already 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 File Reference: COE10505

For additional information on this subject, contact S.B. Jones on 874-1969 or S.P. Cox on 874-2488

Engineering Encyclopedia

Materials & Corrosion Control Corrosion Resistant Characteristics

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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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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Corrosion Resistance Characteristics, Design Practices, and Analysis Methods Corrosion is defined as a deterioration of a material (usually a metal) or its properties due to exposure 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 cross section 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, especially those 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 Steel in 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 as the 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 to provide satisfactory oxidation resistance.

0.05 0.1 0.2 0.5 0.7 1.0 1.5 2.0 4.0

Rference Line

0.03

1600 1700 1800

30 25 20 19 % Nickel in the alloy 18 17 0 16 5 10 15 15 14 20 13 25

1900

30

2000

10.0

35

2

1

40 45

50 60 70

12 % Chromium in the alloy

Moderate Excessive Satisfactory Corrosion rate, in./year Temperature ÞF

0.02

11

10 9 8 7 6 5 4 3

20.0

2 1 0 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, the sulfidation 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, 5Cr 1/2Mo 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 and forms 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 ) 1.437 × Area (SQ DM ) × Days is Service 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 corrosion coupon. 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 8 mpy), 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 on the 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) =

Re maining 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 Remaining Corrosion Allowance 2 years = 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 underdeposit 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 material’s 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 perforation in 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 reach the 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 severe acidic 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 highalloy 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. Corrosion Second Metal Corrosion (iron) (second metal) mg mg Magnesium 0.0 3104.3 Zinc 0.4 688.0 Cadmium 0.4 307.9 Aluminum 9.8 105.9 Antimony 153.1 13.8 Tungsten 176.0 5.2 Lead 183.2 3.6 Tin 171.1 2.5 Nickel 181.1 0.2 Copper 183.1 0.0 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, for example 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 long period 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-tocathode 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 austenitic stainless 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 and Materials/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 today’s 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 environment reduces 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

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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 chloridebearing environment such as wet crude oil, produced water from a production facility or GOSP, 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 Steels—MTI Survey Data

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As shown in Figure 19, chlorides and oxygen can have a synergistic effect on SCC of 304 stainless steel. 1000 SCC - All Heat Treatments

304

SCC No SCC

Annealed

Dissolved O2, g/m (ppm)

100

Sensitized 250 - 300 C

10 SCC Sensitized Only

1

0.1

Tentative SCC - Safe Area

0.01

0.001

0.01

0.1

1

10

100

1,000

10,000

CI Concentration, g/m3(ppm)

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 Types 321 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-0175 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 stress corrosion cracking and the corresponding susceptible materials. It should be noted that this is not a complete list.

CLASSIFICATIONS OF STRESS CORROSION FORMS TYPES OF STRESS CORROSION CRACKING

ALLOY FAMILY

Chloride

Austenitic stainless steel

Polythionic Acid

Austenitic stainless steel (sensitized)

Caustic

Carbon Steel

Wet H2 S

Carbon Steel

Amines

Carbon Steel

Hydrogen

Carbon and low alloy steels

Ammonia

Copper base alloys

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 groovelike 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 brass or 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. Saudi Aramco DeskTop Standards

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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 with hardfacing 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 µm 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 < 20 mpy) in various zones (percent concentration versus temperature). For example, to determine the suitability of Type 316 SS in 40 % H2SO4 at 35 °C (95 °F) the conditions are plotted on the graph (Page 12 of the Appendix) to determine the Zone. In this case, the conditions dictate that a Zone 2 material is required. Examination of Page 13 of the Appendix indicates that Type 316 SS is a Zone 2 material and therefore should be acceptable. Its corrosion rate should be < 20 mpy.

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Corrosion Resistance Strategies Used in Saudi Aramco Saudi Aramco personnel provided some specific examples and information that illustrate the performance characteristics of commonly used materials in various environments. It should be noted that in some instances plausible solutions to the corrosion problems were added by the author for instructional purposes. A summary of these data are provided below: General Corrosion-Resistant Characteristics of Carbon Steel •

Gas Oil Separation Plants (GOSP) These facilities are primarily constructed from carbon steel, although the dehydrators and desalters are internally lined and cathodically protected to minimize corrosion due to produced water. It should be noted that the produced water in a GOSP is very corrosive because it contains high concentrations of NaCl, CO2, and H2S. The sacrificial anodes used to provide the cathodic protection are fabricated from zinc or aluminum.

•

Gas Plants These facilities are also constructed of carbon steel. However, to combat the effects of wet H2S, which promotes hydrogen-induced cracking and blistering of equipment and piping, hydrogen-induced cracking (HIC) resistant steels are used. To ensure that the material is HIC resistant it must meet the requirements of NACE Standards MR-01-75 and TM-02-84. NACE TM-02-84 covers actual HIC testing of heats of steel, while MR-01-75 specifies material and weld hardness limits to minimize the risk of sulfide stress cracking during service.

•

Production Facilities Carbon steel is not suitable for all applications. Excessive internal corrosion of the carbon steel piping was reported in the aquifer water injection system. Apparently, the aquifer water contained a high level of dissolved oxygen which caused the corrosion. If the temperature and chloride content of the water were relatively low, it might have been better to select an alloy material such as Type 316 SS for this service.

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Localized Corrosion-Resistant Characteristics of Carbon Steel •

In a cross-country pipeline located in a subka region, external corrosion occurred on a carbon steel pipeline beneath failed to tape wrap. This rendered the cathodic protection system ineffective. To restore the effectiveness of the cathodic protection system, it was necessary to repair the corrosion damage and replace the tape wrap with a protective coating (FBE).

•

Dead-leg corrosion occurred on the internal surface of a carbon steel crude oil transmission line due to stagnant conditions. The dead-leg area contained oil, water, and debris. This type of corrosion can be corrected by using an alloy material, or by providing the capability to periodically drain the dead-leg. However, draining requires maintenance and this might be difficult in an isolated area. The best solution, if possible, would have been to eliminate the dead-leg area in the pipeline during the design phase.

General Corrosion-Resistant Characteristics of Stainless Steel •

GOSP On offshore GOSP facilities the seawater and firewater piping systems are fabricated from Avesta 254 SMO. Thinner wall piping was used because of the improved corrosion resistance and strength of this alloy. This resulted in a significant weight savings, an extremely important consideration on offshore platforms.

•

Gas Plants Stainless steels are used in various applications in these facilities. Type 316L SS is used for the pelletizing towers and associated piping in a Sulfur Unit. The top portion of the Regenerator Column in a Gas Sweetening Plant utilizes carbon steel clad with Type 304 SS to minimize corrosion due to H2S and CO2. In an acid gas scrubber, the internals (trays and pall rings) are Type 304 SS. Flare stack burner tips have Type 310 SS heat shields which protect adjacent components from high temperature sulfidation and oxidation.

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Localized Corrosion-Resistant Characteristics of Stainless Steel •

Gas Plant and Utilities Pitting failure occurred at piping welds due to sensitization of the stainless steel. In general, to minimize sensitization and subsequent corrosion problems in the weld area, either low-carbon “L” grades or stabilized grades (Types 321 or 347) of stainless steel should be specified. An alternative is to use low-heat input welding techniques.

•

Refinery Condensation and chloride-related corrosion occurred under insulation on stainless steel components. Corrosion under insulation is particularly damaging to austenitic stainless steel. In addition to pitting, the material might fail in a catastrophic manner due to chloride stress corrosion cracking. There are several options that can be exercised to minimize this form of corrosion. The best option might be to use insulation that has very strict limits on the amount of water-leachable chloride. Other options might be to install heat tracing to keep metal temperature above the dew point during shutdowns, or to use sealants to minimize water and moisture ingress.

•

Production Facilities Chloride SCC occurred on stainless steel instrument piping exposed to the marine atmosphere on offshore platforms. The solution to this type of problem in most situations is to upgrade or change the material. Depending on the temperature, it may be possible to utilize duplex stainless steels such as SAF 2205 or 3RE60. High nickel alloys such as Alloy 20Cb3, Incoloy 825, 904L, or Monel 400 could also be considered.

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General and Localized Corrosion-Resistant Characteristics of Other Commonly Used Materials Nickel-Base Alloys •

Refinery Satisfactory service experience was reported for Monel lining in pressure vessels, Inconel 718 for valve trim, and Inconel 625 weld overlay of a pump shaft in seawater service. In general, nickel-base alloys possess superior resistance to chloride SCC. Alloys containing greater than 13 wt. % chromium are recommended for high-temperature service where oxidation resistance and high-temperature strength are critical. However, it must be recognized that these alloys are unsuitable for elevated temperature service in sulfur-bearing environments. As a family, the alloys are susceptible to catastrophic sulfidation under these conditions. An example of an unacceptable application of nickel-base alloys was the use of Monel in an oxidizing environment at elevated temperatures. Alloys like Monel that contain no chromium are generally unsatisfactory for service under oxidizing or sulfiding conditions.

•

Offshore Facilities Monel material gives very good performance in seawater and consequently has been used for sheathing for splash zone protection on offshore platforms. Copper-Base Alloys

•

Some copper-base alloys are susceptible to corrosion in wet H2S bearing streams. Unsatisfactory experience was reported with 70/30 and 90/10 coppernickel tubes because of process side scaling due to wet H2S. A better tube material for this service might have been Admiralty brass, as this material has good resistance to wet H2S and is commonly used in process stream cooling water condensers. However, it has limited strength at metal temperatures above 120 °C (250 °F).

•

Uninhibited, high zinc brasses, such as Muntz Metal (60Cu-40Zn), yellow brass (67Cu-33Zn), and aluminum brass (76Cu-22Zn-2Al), are susceptible to dezincification in soft waters. It was reported that this type of corrosion occurred in domestic plumbing systems in brass materials in raw water service. The use of an inhibited material, such as Admiralty or inhibited aluminum brass, or a low-zinc brass such as Red Brass (85Cu-15Zn), should result in a longer service life. Information on the corrosion rates of brasses in hydrogen sulfide can be found in the Corrosion Handbook edited by H.H. Uhlig, 1948.

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Refer to the section covering Copper-Zinc alloys. In addition Admiralty Brass is used by refiners for cooling water exchanger tubing that has hydrogen sulfide bearing streams on the process side. Titanium •

Titanium is an extremely corrosion-resistant material that is resistant to most of the environments encountered in the petroleum industry. It is used primarily for heat exchanger tubing in brackish or seawater cooling service. It was reported that titanium tubes (SB338 Gr 2) were installed in a heat exchanger in which natural gas is cooled using chlorinated seawater. The gas is on the shellside, and the chlorinated seawater is on the tubeside. It should be noted, however, that under certain conditions titanium is susceptible to embrittlement due to hydriding. This phenomenon occurs when titanium is in contact with a dissimilar metal, such as carbon or stainless steel, in an extremely corrosive environment. The hydrogen generated during the corrosion of the carbon or stainless steel dissolves in and embrittles the titanium.

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REFERENCES 1. R. Merrick, “Refinery Experiences with Cracking in Wet H2S Environment, NACE Corrosion 87 Paper. 2.

NACE Corrosion Data Survey, Metals Section.

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