Continued Studies of Corrosion by Fused Caustie

Boiler tube failures

Atanu Saha , in Handbook of Materials Failure Analysis with Case Studies from the Chemicals, Concrete and Power Industries, 2016

1.4 Caustic Corrosion/Gouging

Caustic corrosion/gouging occurs when alkalinity of boiler water increases. Caustic corrosion is also called caustic attack. Caustic corrosion develops from deposition of feed water corrosion products in which NaOH can concentrate to high PH levels. At high PH level, the tube steel's protective magnetic oxide coating is solubilized and rapid corrosion occurs as per the reaction given below:

$4\mathrm{NaOH}+{\mathrm{F}\mathrm{e}}_3{\mathrm{O}}_4=2{\mathrm{NaFeO}}_2+2{\mathrm{H}}_2\mathrm{O}$

With the destruction of protective magnetic oxide layer, concentrated NaOH reacts with the tube material and forms atomic hydrogen as per the reaction

$\mathrm{F}\mathrm{e}+2\mathrm{NaOH}={\mathrm{N}\mathrm{a}}_2{\mathrm{F}\mathrm{e}\mathrm{O}}_2+2\mathrm{H}$

The atomic hydrogen so produced reacts with Fe₃C of pearlite constituent and forms CH₄ which ultimately causes hydrogen damage, discussed earlier. The tube surface deposits accumulate at locations where flow is disrupted such as, welds with backing rings, at bends, in horizontal tube weld, and at high-heat input locations. Figure 3.2 shows the locations of the boiler where caustic corrosion can occur and Figure 3.6 shows caustic corrosion gouging of a boiler tube.

Figure 3.6. Caustic corrosion gouging. Severe localized gouging on the heat absorption side of this SA-210 waterwall tube was caused by caustic corrosion beneath a deposit. Once the caustic concentration within a deposit becomes grate enough to cause corrosion, the reaction becomes self-perpetuating and causes a through-wall leak within a very short time [3].

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Failure analysis of heat exchanger tubes in petrochemical industry

Zhen-Guo Yang , Yi Gong , in Handbook of Materials Failure Analysis with Case Studies from the Oil and Gas Industry, 2016

3.2.5 Discussion

Based on the analysis results above, it can be concluded that both caustic and acidic corrosions were involved in this case, though it seemed contradictory. Furthermore, at least four types of defects in four different scales were discovered, including cavity (~   2   μm), coin (~   10   μm, with coral structure), pit (~   100   μm), and concave (several millimeters). Therefore, in order to better illustrate this extraordinary failure mechanism with versatile morphologies, a novel acidic/caustic alternating corrosion mechanism was proposed.

According to the pH monitoring data of the process water, especially at site II and III, the QO/DS heat exchanger tubes had been subjected to an over alkaline (pH   > 9.5, even reached 11.5) environment for a long time. Consequently, caustic corrosion (called caustic embrittlement more accurately, a specific kind of stress corrosion cracking) was engendered on the carbon steel tubes under both concentrated NaOH and tensile stress (because the operational pressure of the tube side was larger than the shell side), and corrosion products including Na ₃FeO₃, Na₂FeO₂, and FeO _x were formed, as seen in Equation 16.2. However, since the pH value of the process water fluctuated so frequently and drastically, the caustic corrosion would be substituted by the acidic corrosion once it dropped into the lower range (<   7.5). Indeed, it is not difficult to infer that the sulfur element in the corrosion products must have resulted from the acidic corrosion induced by SO₂, H₂S, and particularly sulfuric acid (H₂SO₄), while the chlorine element and the typical morphologies (Figure 16.14) was the solid evidence of pitting corrosion, which commonly occurs in acidic environments as well. Therefore, it could be concluded that both the caustic and acidic corrosions emerged on the QO/DS heat exchanger tubes in an alternating modes due to the frequent fluctuations of the process water pH values. Of course, considering the duration of pH values in the alkaline range was far longer, the caustic corrosion should be the dominant factor in this case.

(16.2) $\begin{array}{l}3\mathrm{F}\mathrm{e}+7\mathrm{NaOH}\to {\mathrm{N}\mathrm{a}}_3{\mathrm{F}\mathrm{e}\mathrm{O}}_3\cdot 2{\mathrm{N}\mathrm{a}}_2{\mathrm{F}\mathrm{e}\mathrm{O}}_2+7\mathrm{H}\\ {\mathrm{N}\mathrm{a}}_3{\mathrm{F}\mathrm{e}\mathrm{O}}_3\cdot 2{\mathrm{N}\mathrm{a}}_2{\mathrm{F}\mathrm{e}\mathrm{O}}_2+4{\mathrm{H}}_2\mathrm{O}\to 7\mathrm{NaOH}+{\mathrm{F}\mathrm{e}}_3{\mathrm{O}}_4+\mathrm{H}\\ 3\mathrm{F}\mathrm{e}+4{\mathrm{H}}_2\mathrm{O}\to {\mathrm{F}\mathrm{e}}_3{\mathrm{O}}_4+4{\mathrm{H}}_2\end{array}$

In fact, both the caustic and the acidic corrosions were localized forms of corrosion, hence this alternating corrosion mechanism would preferentially propagate at localized sites where either was initiated in advance (dominantly the caustic corrosion); in other words, they would occur at the same sites. As a result, corrosion products containing not only sodium (from caustic corrosion) but also sulfur (from acidic corrosion) were generated, as seen the EDS results in Table 16.8. With respect to the corrosion morphologies, if chlorides were not involved (i.e., free of pitting corrosion), only the coral structure from caustic embrittlement [10] would develop (~   10   μm; Figure 16.13d), and would be accompanied by microcracks due to hydrogen embrittlement (Equation 16.2 and Figure 16.13c). If chlorides existed as well, pitting corrosion would be initiated simultaneously, and a cavity with a size of approximately 2   μm would develop in the center of the coral-structure corrosion products, forming the shape of a coin (Figure 16.13b). Thereafter, with the progress of corrosion, adjacent coins would be connected and larger pits (~   100   μm) would develop, and eventually concaves with even larger sizes (several millimeters) would be formed by the connection of such pits. Meanwhile, corrosion would also develop downwards and finally result in perforation.

So far, how this acidic/caustic alternating corrosion was initiated and propagated was clarified, and the corresponding morphologies in different scales during the process were also revealed. Now the focus should be shifted to the causes of the frequent and drastic fluctuation of the pH values as well as the origins of the sulfides and the chlorides. By means of field investigation, it was found that the 20   wt% NaOH solution was usually fed without cautious quantity control by operations. For example, the total amount needed for the whole night was possibly added into the process water just once before night shift. As a result, the pH value would suddenly jump to the high alkaline range (>   9.5), even exceeding 11.5 at times. Under such circumstances, inorganic acids, usually H₂SO₄ would be additionally injected for neutralization. Consequently, the pH value would suddenly drop to the lower range again, with some readings below 5.5, while simultaneously introducing aggressive sulfides. Hereby, the underlying causes of this acidic/caustic alternating corrosion was identified, which could be briefly summarized as an operational error, again another one of the human factors. As for the chloride, the NaOH that is usually produced by electrolysis of saturated salt water, the inorganic acids, or the process water itself were all possible sources, but it was not of major importance in this case.

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Main Equipment

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook (Second Edition), 2019

2.10.11.1 Tube Inside or Water-side Corrosion

The problem is most likely to develop during boiler start-up cycles. This type of failure is observed at the inner side of the pipe with wide transgranular cracks, which typically occur adjacent to external attachments and weldments such as buck stays, seal plates, scallop bars, etc. A combination of some damaging factors leads to the breakdown of the protective magnetite of the inside surface of the boiler tube. Corrosion of the tube surface then starts in the absence of this protective layer.

This type of corrosion may typically be caused by:

(a)

Caustic corrosion , which may be caused by:

•

Random build up by FW-borne deposits or preboiler corrosion products at locations of high heat flux.

•

Concentration of sodium hydroxide due to chemicals carried over by the feed water.

(b)

Pitting or localized corrosion, which is normally affected by:

•

FW with high acidic or oxygen concentrations.

•

Existence of close-fitting surfaces and deposits where differences in oxygen concentration can be produced.

(c)

Stress corrosion cracking (SCC)

The combined effect of high-tensile stresses and the presence of corrosive fluids is responsible for this type of failure. Stress corrosion cracking (SCC) failures are distinguished by the brittle type of crack with a noticeable thickness. These failure locations are also observed near the source of higher external stresses such as attachments. The corrosive fluid may come as carryover from the steam drum into the superheater or may get contaminated during boiler acid cleaning without the faulty superheater protection. Normally, austenitic (stainless steel) superheater tubes are subjected to SCC and can propagate in the tube wall from the inner wall surface with transgranular or intergranular cracks.

(d)

Hydrogen embrittlement

Hydrogen embrittlement is a most common type of failure effected by the combined outcome of excessive deposition on inside tube surfaces and the boiler FW having a low pH value. The digression of water chemistry or acidic contaminants, that is, low pH, resulting through, for example, condenser leakage particularly with a saltwater cooling medium, may cause further deposition and concentrate on the build up already taken place. The resultant deposit initiates corrosion, which releases atomic hydrogen that propagates into the tube metal wall and reacts with the carbon present in the steel. This phenomenon is called decarburization and causes intergranular separation or intergranular microcracking. The final damage done is the loss of ductility or embrittlement of the tube material, leading to tube failure with severe rupture.

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NDT for Non-Nuclear Power Generation: Pressure Vessels, Piping, and Turbines

A. Birring , in Encyclopedia of Materials: Science and Technology, 2001

1.2 Inner Diameter Corrosion, Hydrogen Damage, Caustic Corrosion, Chemical Attack

Inner diameter (ID) pitting in boiler tubes can be caused by hydrogen damage, caustic corrosion, chemical attack, etc. Because this type of pitting is usually isolated, a careful examination of the whole boiler tube length is required. Digital gauges have severe limitations when measuring tubes with ID pitting. Ultrasonic scattering from ID pits produces an undefined back-surface reflection signal and impairs thickness measurement. When measuring the thickness of a tube with ID surface corrosion, an instrument with a CRT screen display is recommended. The screen presentation identifies the back-wall reflection so as to give reliable thickness measurements.

Hydrogen damage is one of the mechanisms that produces ID corrosion. This damage is produced in the water wall tubes from an imbalance in water chemistry (French 1993). Tube bends, circumferential welds, and tube lengths across the burners are the most susceptible locations for such damage. Hydrogen damage is of serious concern because it not only results in ID wall loss but also in a zone of decarburized material under the corroded area. Ultrasonic thickness scanning is the first step towards detection of corrosion caused by hydrogen damage. Since ID corrosion can be caused by other mechanisms, hydrogen damage should be verified by other NDT methods. Decarburization caused by hydrogen damage reduces the ultrasonic velocity, and so velocity measurement techniques can therefore be applied for verification of such damage.

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Corrosion Atlas

In Corrosion Atlas Case Studies, 2022

Case History 01.20.04.001

Type of Material	Low carbon steel—St 35.8
System	Boiler tube having treated boiler feed water
Name of the Part	Tube/pipe Operating temperature: 250°C Operating pressure: 60 Barg
Phenomenon	Caustic corrosion/houging associated with irregular wall thinning and gouging of the tube
Appearance	Thick, porous, and multilayered deposits were present on the inner surface of the tube; in a localized area. Thinning was observed under the deposits.
Time in Service	Four years
Environment	The microstructure consisted of ferrite and pearlite. Copper particles were present throughout the scale. Copper compounds can enhance the corrosion process by causing increased magnetite formation. The deposits were found to be predominantly magnetite which was the normal protective layer that formed on boiler tube surfaces. Other elements were also found such as bromine, chlorine, copper, and manganese. Traces of sodium were also found.
Causes	Caustic corrosion/gouging
Remedy	• In the literature (5), it states that caustic soda should not be present in high-pressure boilers; in its place, a coordinated phosphate programme should be used. • Minimize the amount of available free sodium hydroxide or other corrosive species. • Applying a water treatment, for example, removing any suspended solids, decreasing cycles of concentration and clarification. • Elimination of hot spots caused by over firing, misadjusted burners, change of fuel, etc. • Regular cleaning involving mechanical methods to remove any deposit build up. Water blasting, air rumbling, and chemical cleaning are often employed.
Additional References Pertaining to Case Study	• API RP 571, Damage Mechanisms, 2020, USA • Port, R.D., Herro, H.M., 1991. The NALCO guide to boiler failure analysis. Chapter 4: Caustic Corrosion. • Shalaby, H.M., A new understanding for the mechanism of caustic gouging of boiler tubes. NACE corrosion 2007 conference. Paper 07453 • Port, R.D., Herro, H.M., 1993. The NALCO guide to boiler failure analysis. Chapter 4: Under-deposit Corrosion

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WATER ELECTROLYSIS AND ELECTROCHEMICAL RECOMBUSTION OF HYDROGEN IN FUEL CELLS; A MEANS FOR ENERGY CONVERSION AND STORAGE

H. Wendt , in Energy: Money, Materials and Engineering, 1982

Metal net backed porous oxide ceramic diaphragms

T.H. Darmstadt (Fischer [13] ) has developed a diaphragm made of porous oxide ceramic material which does not dissolve in highly concentrated alkaline solution even at process temperatures exceeding 160 °C. The oxide ceramic being intrinsically a very brittle material coats a woven metal net which is stable against caustic corrosion and which supplies the oxide ceramics with the flexibility necessary for the engineering–purpose to be incorporated into large scale electrolyzers. The diaphragms are being produced with thicknesses between 200 and 400 μm and possess surface specific resistances between 0.2 and 0.3 Ωcm² under operation conditions. Raw materials and production procedures are relatively expensive for these diaphragms so that with an estimated prize of 60 US-dollars per m² this solution of the diaphragm problem seems to be most costly of all.

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Main Equipment

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook, 2015

2.3.11.1 Tube Inside or Waterside Corrosion

The problem is most likely to develop during the boiler startup cycles. This type of failure is observed at the inner side of the pipe with wide transgranular cracks that typically take place adjacent to external attachments and weldments, such as buck stay, seal plates, scallop bars, etc. A combination of some damaging factors leads to the breakdown of the protective magnetite of the inside surface of the boiler tube. Corrosion of tube surface then starts in the absence of this protective layer. This type of corrosion typically results from:

Caustic corrosion that may be caused by:

•

Random build up by feedwater-borne deposits or preboiler corrosion products at locations of high heat flux.

•

Concentration of sodium hydroxide due to chemicals carried over by the feedwater.

Pitting or localized corrosion that is normally affected by:

•

Feedwater with a high acidic or oxygen concentration.

•

Existence of close-fitting surfaces and deposits where differences in oxygen concentration can be produced.

Stress corrosion cracking (SCC): The combined effect of high-tensile stresses and the presence of corrosive fluids are responsible for this type of failure. SCC failures are distinguished by the brittle type of crack with a noticeable thickness. The failure locations are also observed near the source of higher external stress such as attachments. The corrosive fluid may be a result of carryover from the steam drum into the superheater or may get contaminated during boiler acid cleaning without the faulty superheater protection. Normally, austenitic (stainless steel) superheater tubes are subjected to SCC and can propagate in the tube wall from the inner surface with a transgranular or intergranular crack.

Hydrogen embrittlement: This is a most common type of failure affected by the combined outcome of excessive deposition on inside tube surfaces and the boiler feedwater that has a low pH value. Digression of water chemistry or acidic contaminants—that is, low pH—resulted from, for example, leakage of the condenser particularly with a salt water cooling medium; this may cause further deposition and concentration of the buildup already taking place. The resultant deposit initiates corrosion that releases atomic hydrogen, which propagates into the tube metal wall and reacts with the carbon present in the steel. This phenomenon is called decarburization and causes intergranular separation or intergranular microcracking. The final damage done is the loss of ductility or embrittlement of the tube material leading to tube failure resulting in severe rupture.

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Radiation Technology Application in High-Performance Fibers and Functional Textiles

Weihua Liu , ... Guozhong Wu , in Radiation Technology for Advanced Materials, 2019

2.2.1 High-performance fibers and composites

Compared with traditional natural fibers such as cotton, linen, and man-made fibers such as polyester and polypropylene (PP) fibers, high-performance fibers have some excellent properties, such as extremely high strength modulus, high thermal stability, and good acidic and caustic corrosion resistance. Kevlar fiber, ultrahigh molecular weight polyethylene (UHMWPE) fiber, and CF are three representative high-performance fibers. High-performance fibers are not only widely used in national defense, aerospace, and other high-end fields, but also play an important role in civilian applications including transportation, construction, and sports goods.

For fiber reinforced composites, the adhesion strength between reinforcing fibers and the resin matrix determines the properties of composites. A strong interfacial strength can make the load on the composite transfer more effectively between the fibers and the resin matrix. As high-performance fibers are mostly constructed of rigid macromolecular chains and possess high crystallinity, the fiber surface is very smooth and lacks chemically active groups, leading to poor interface adhesion strength between fibers and the resin matrix. Consequently, the load transfer is inefficient, limiting the application of composites. It is reported that the strength conversion ratio of aramid fiber reinforced composites is only 68%–76%, which is even lower than that of glass fiber (>80%). ¹⁵ In order to improve the interfacial bonding ability between the fiber and the matrix resin, the surface of high-performance fibers must be modified by physical or chemical methods. Physical modification methods include surface coating, plasma, and EB and γ-ray irradiation. The chemical methods include surface activation and surface grafting. Although the surface of high-performance fibers can be modified using many methods, there are still some limitations. Surface coating has the advantages of simple operation, easy control, and no damage to the fiber, but the effect is insignificant; plasma treatment can introduce polar functional groups on the fiber surface, and improve surface wettability, but it is difficult to achieve in an online continuous operation. Surface grafting by chemical methods not only increases the compatibility between the high-performance fiber and the resin matrix, but also introduces active groups on the surface of the fiber. This method can significantly enhance the adhesion strength of the fiber and the resin matrix. However, chemical surface grafting often takes a long time and the activity of chemical reaction is difficult to control. The application of high energy irradiation (γ-ray and EB) in the modification of polymer materials has proven to be a good choice for improving the surface compatibility of high-performance fibers. Since irradiation generates a large number of free radicals in the fibers, these radicals can trigger the grafting polymerization of acrylate monomers on the fiber surface, leading to the complete surface modification of high-performance fibers (Fig. 2.23).

Figure 2.23. Radiation-induced surface modification of high-performance fibers and its application in composites.

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Part III: Corrosion in Water-Bearing Systems

In Corrosion Atlas Case Studies, 2022

Water-Side Corrosion in Boilers

Oxygen Corrosion

Oxygen corrosion remains a frequent problem in boilers. It can be caused by insufficient deaeration of the feedwater in the operational stage or by poor preservation during periods of shutdown. The mechanism of oxygen corrosion is fairly simple. In the absence of oxygen and temperatures above 120°C, water reacts with iron, forming magnetite (according to the Schickor reaction). This black iron oxide (Fe₃O₄) forms a protective skin on the metal surface:

$3\text{Fe}+{4\text{H}}_2\text{O}\to {\text{Fe}}_3{\text{O}}_4+{4\text{H}}_2\uparrow$

The magnetite skin prevents further corrosion. However, if regular supplies of oxygen occur at a later stage, this layer is broken down and converted into a nonprotective layer of hematite (Fe₂·O₃):

${4\text{Fe}}_3{\text{O}}_4+{\text{O}}_2\to {6\text{Fe}}_2{\text{O}}_3$

During operation, the economizer is most sensitive to oxygen corrosion, but fire tubes can also be attacked. During shutdown, this form of corrosion occurs on the fire tubes of fire-tube boilers and in the water tubes and drums of water-tube boilers (01.01.01.06/08). Control of this corrosion obviously requires an efficient deaerator. Other suitable measures are additional deaeration by dosing an oxygen scavenger (see also Corrosion in Condensate Systems) and improving the preservation method.

Caustic Corrosion

Corrosion in boilers is often due to an incorrect pH setting. Both an excessively high and an excessively low pH may be the source of the problem. In boilers, caustic corrosion is above all a consequence of extreme concentration of the boiler water underneath scale deposits or in crevices. Initially, the protective magnetite skin dissolves as follows:

$4\text{NaOH}+{\text{Fe}}_3{\text{O}}_4\to {2\text{NaFeO}}_2+{\text{Na}}_2{\text{FeO}}_2+{2\text{H}}_2\text{O}$

Next, caustic and water react directly with the steel as follows:

$\text{Fe}+2\text{NaOH}\to {\text{Na}}_2{\text{FeO}}_2+{\text{H}}_2\uparrow$

$3\text{Fe}+{4\text{H}}_2\text{O}\to {\text{Fe}}_3{\text{O}}_4+{4\text{H}}_2\uparrow$

Another consequence of highly alkaline boiler water may be caustic stress corrosion cracking, leading to cracking (and Part II, Chapter 12).

Acid Corrosion

Acid corrosion in boilers can be caused by magnesium chloride–containing cooling water entering the condensate system. This can take place, for example, via a seawater-cooled condenser of a power plant. If such acid-forming salts occur in high local concentrations, small quantities of hydrochloric acid are formed by hydrolysis:

${\text{MgCl}}_2+{2\text{H}}_2\text{O}\to \text{Mg}{\left(\text{OH}\right)}_2+2\text{HCl}$

Other chloride-containing contaminants can also produce hydrochloric acid by decomposition under certain conditions.

Even if the bulk of the boiler water reacts alkaline, the acid need not necessarily be neutralized immediately. This is because porous deposits, crevices, or poor boiler water circulation may prevent thorough mixing of the water. This enables local sharp decreases in pH. The hydrochloric acid then attacks the steel as follows:

$\text{Fe}+2\text{HCl}\to {\text{FeCl}}_2+{\text{H}}_2\uparrow \left(01\text{.}01\text{.}04\text{.}05\right)$

In fire-tube boilers, a similar type of acid corrosion sometimes occurs if dosing of sodium bisulfite is adopted for the chemical bonding of oxygen. Particularly, when this is applied not in addition to but instead of thermal deaeration, there will usually be an extremely high sulfate concentration in the boiler water. Presumably, under such conditions, acid is formed by hydrolysis.

Other sources of acid contamination of boiler water are the entrainment of regeneration acid with the makeup water or of acid or acid-forming products with the condensate.

Finally, acid corrosion can also occur when chemical cleaning treatments of boilers are poorly performed or poorly inspected.

Hydrogen Attack

Both acid attack and caustic attack of steel initially cause the formation of atomic hydrogen. Hydrogen damage may result (see Part II, Chapter 8). The atomic hydrogen diffuses into the steel and reacts with iron carbide, with formation of methane.

The pH can be controlled by means of appropriate boiler water conditioning and daily testing of the feedwater and boiler water composition, which will prevent this form of corrosion.

Erosion Corrosion

In boilers, erosion corrosion occurs particularly in evaporator tubes if excessive steam formation leads to excessively high water velocity. In an over-dimensioned economizer, undesirable steam formation can occur in the economizer tubes. This leads to erosion corrosion particularly in the bends. Turbulence can cause erosion corrosion at other sites in the boiler. Research carried out by KEMA Nederland B.V. in Arnhem, Holland, has shown that a causal relationship exists between the contents of copper, chromium, molybdenum, and carbon, and the erosion corrosion resistance of carbon steel in water–steam systems. This is specified as the G_KEMA value, which can be calculated as follows:

${\text{G}}_{\text{KEMA}}=90-160\text{. Cu}-115\text{. Cr}-40\text{. Mo}+35\text{. C}$

Erosion corrosion-resistant material for water–steam systems should have a G_KEMA value of at most 80.

Chelant Corrosion

Chelant corrosion is a risk if complex binders are dosed as part of the boiler water conditioning procedure. For example, dosing with sodium ethyl diamine tetra-acetic acid can cause the steel to be attacked as follows:

${\text{Fe}}_3{\text{O}}_4+\text{Fe}+8\text{H}+4\text{CH}\to 4\text{Fe}\left(\text{II}\right)\text{CH}+{4\text{H}}_2\text{O}$

$\left(\text{CH}=\text{chelate}\text{molecules}\right)$

This chelant corrosion produces a typically uniform corrosion picture without specific characteristics. If the flow velocity is sufficiently high, there may be a wavy surface with areas of damage resembling comet tails and horseshoes. Oxygen is a strong promoter of the formation of chelant corrosion. The risk is also increased by overdosing and local concentration of the complex binder. It is quite clear that these conditioners must be dosed with particular care. In order to prevent chelant corrosion, the levels of complex binder and oxygen in the feedwater must be carefully checked. Practice has shown that this form of corrosion occurs in the steam drum and downcomers but also in the feedwater line. Because places with a large heat flux are extra sensitive, hot spots in the boiler should be avoided.

Heat-Flux Corrosion

A number of different corrosion processes can be strongly accelerated at sites where there is a high heat flux; logically, this is called heat-flux corrosion.

Liquid Metal Embrittlement

During welding or high-temperature operation, copper-containing deposits in boilers can lead to cracking as a result of liquid metal embrittlement. This is caused by molten copper penetrating into the steel along austenite grain boundaries, causing intergranular cracking and failure of the pipes.

Prior to overhaul, any copper deposit present should be removed by chemical cleaning, incorporating a copper removal step in order to prevent copper plating.

Steam Blanketing

Obliquely rising water tubes, for example, at the bottom of water-tube boilers, are particularly sensitive to damage by thermal stresses. Here, the protective oxide skin of magnetite (Fe₃O₄) can sometimes be so badly damaged that leakage results.

For example, circulation upsets or strong radiation may cause an intensive boiling process in these tubes, whereby steam bubbles remain attached to the heated upper side of the tube and form a local steam blanket. This results in a local sharp decrease in cooling, and enhanced oxidation takes place (formation of magnetite). If the steam blanket is expelled by load fluctuations (caused by changed circulation), the cooling will temporarily recover, and the formed oxide can flake off.

This steam blanketing can cause substantial loss of wall thickness in a comparatively short time (0.01.43.01). In the case of concentration of salts underneath the steam film, steam blanketing can also cause acid and caustic corrosion and even lead to hydrogen damage (see Part II, Chapter 8).

Steam blanketing can be prevented either by reducing the heat load at these sites, that is by applying thermal insulation or by structurally improving the circulation in the tubes concerned. In addition, appropriate water treatment should be applied in order to prevent the formation of circulation-impeding deposits.

Corrosion by Overheating

Steel in a boiler can become overheated. This may be caused by excessive radiation from the furnace or insufficient cooling. Cooling may be impeded by deposits in the evaporator section or superheater causing blockages. The overheating causes the steel to lose strength, and it begins to creep and bulge, which results in cracking. This phenomenon occurs frequently in boilers. In itself, this is not strictly corrosion, but the high steel temperature will cause the oxidation process to accelerate, thereby forming an undesirably thick oxide skin. When the pipe wall cools (during shutdown), the over-thick oxide skin will be subjected to stress and spall off. In a following operational period, locally strong oxide growth will recur. If this cycle is repeated a number of times, the lifetime of the tubes may be substantially reduced. If this phenomenon occurs in the final superheater, the hard oxide particles entrained with the steam can cause erosion of the steam-consuming equipment (e.g., the turbine blades).

Overheating can be prevented by correcting an unbalanced heat distribution, improving the cooling, or by applying different steel grades capable of withstanding higher temperatures. Thermally insulating and blocking deposits can play an important role in overheating. The formation of deposits can be prevented by effective boiler-water treatment together with appropriate monitoring.

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Methods for studying erosion–corrosion

R.G. Wellman , in Tribocorrosion of Passive Metals and Coatings, 2011

9.1 Introduction

The term erosion–corrosion is very broad and refers to any system where both erosion (material loss due to particle impact) and corrosion (chemical attack/modification of the exposed surface) occur simultaneously. Although normally associated with an acceleration of degradation, this is not always the case. In some cases the formation of an oxide scale can protect the metal from damage caused by the impacting particles. However, in the vast majority of cases the interaction of the impacting particles with the oxide/passivating layer results in an increase in the overall rate of material loss from the surface. The broad nature of erosion–corrosion becomes evident when one examines the range of rigs available to study this field; each one intended to simulate a different industrial process. Thus erosion–corrosion can refer to aqueous slurry erosion (often containing 3.5 weight% NaCl and sand particles) or actually mean erosion–oxidation in a gas turbine at over 1000 °C or erosion-fire side corrosion in a coal-fired boiler or erosion-caustic corrosion at 70–150  °C in chemical processing plant.

Erosion–corrosion is a relatively new branch of materials science with the first reference to erosion–corrosion (as recorded in Scopus) being in a paper by Venzcel et al. on the corrosion and erosion–corrosion of copper alloys and a low carbon steel in a 3 weight % NaCl solution in 1964. ¹ Since then the number of papers published on erosion–corrosion has increased steadily with a discernible peak in the late 1980s. This peak was driven by research into the performance of materials used in fluidised bed combustion (FBC). systems ^2–4 However, more recently there has been a surge in publications in the field driven by a number of different sectors including the oil and gas, power generation, offshore and aerospace industries.

Erosion is a phenomenon that affects numerous sectors causing material loss and eventually component failure. Similarly, corrosion (said to cost between 1 and 5% of a country's GDP) ⁵ leads to the failure of components in many diverse industries. However, the worst case scenario is normally under conditions where both erosion and corrosion occur, resulting in vastly accelerated material loss.

Erosion–corrosion typically involves the impact of solid particles carried in a fluid (which, in the absence of the particles, would lead to corrosion or oxidation) against a structure or component resulting in the loss of material, which unchecked will result in failure. In cases where the fluid is corrosive the chemical attack can either increase or decrease the rate of material loss, although in most cases, the result is a significant increase in wastage rates. The phenomenon of erosion–corrosion can occur under vastly different conditions at gas and particle velocities of 200–300   m/s at 1100   °C (turbines) or at particle velocities of 1–10   m/s at 350–550   °C (FBC) or at ambient temperature. In all of these cases the impacting particles, the fluid carrying the particles and the operating temperatures are significantly different and hence the test rigs needed to study the phenomena are different. To further complicate the issue, the fluid carrying the solid particles can be either a liquid (in which case the term slurry erosion is often used) or a gas (which often implies high temperatures). So erosion–corrosion can be broadly divided into two categories: slurry erosion and high temperature erosion–corrosion (which incorporates high temperature erosion–oxidation). High temperature erosion–corrosion can be subdivided by velocity: low velocity, typically 1–40   m/s, and high velocity, typically in the region of 200–300   m/s. The various industries most affected by erosion–corrosion have been summarised according to velocity and temperature in Table 9.1.

Table 9.1. Examples of industrial erosion–corrosion issues as a function of the velocity and temperature

	Low temperature	High temperature
Low velocity	Offshore and marine structures	Fluidised bed
	Slurry transportation of solids	combustors
	Chemical processing	Coal-fired boilers
	Exhaust valves	Chemical processing
High velocity	Oil and gas industry	Aero engines
	Mining	Oil and gas industry
	Fuel injection systems	Steam turbines
		Gas turbines
		Turbo chargers

The mechanisms of erosion–corrosion are discussed in Chapter 6. This chapter is more concerned with the methods and test rigs used to study slurry erosion and high temperature erosion–corrosion. This chapter not only looks at the available methods and the various test rigs that are available/have been used to study the phenomenon of erosion–corrosion, but also briefly looks at the importance of using scanning electron microscopy (SEM) to examine eroded surfaces. Ideally the test rigs need to be able to distinguish between mass loss due to impacting particles, the mass loss due to chemical/corrosive/oxidation effects and the mass loss due to the combined effects. Although the rate of removal is determined by the rig, it is the post-testing examination of the test pieces, both top view and in cross-section, which often gives the important information about the erosion mechanisms taking place.

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https://www.sciencedirect.com/science/article/pii/B9781845699666500099

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Source: https://www.sciencedirect.com/topics/engineering/caustic-corrosion

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