Keywords

Chemistry of corrosion; naphthenic acid corrosion; sulfidic corrosion; physical effects; furnace tubes and transfer lines; atmospheric column; vacuum column; side-cut piping

2.1 Introduction

Corrosion is the deterioration or destruction of metals and alloys in the presence of an environment by chemical or electrochemical means (Chapter 1).

Corrosion is an irreversible interfacial reaction of a material (metal or ceramic or polymer) with its environment which results in its consumption or dissolution into the material of a component of the environment. Often, but not necessarily, corrosion results in effects detrimental to the usage of that material considered. Exclusively physical or mechanical processes such as melting and evaporation, abrasion or mechanical fracture are not included in the term corrosion.

Corrosion is a natural phenomenon and is the deterioration of a material as a result of its interaction of the material with the surroundings (Fontana, 1986; Garverick, 1994; Shreir et al., 1994; Jones, 1996; Shalaby et al., 1996; Peabody, 2001; Bushman, 2002; Landolt, 2007). Although this definition is applicable to any type of material, it is typically reserved for metallic alloys (Speight, 2014b). Furthermore, corrosion processes not only influence the chemical properties of a metal or metals alloy but also generate changes in the physical properties and the mechanical behavior.

Corrosion is an ever-present phenomenon in refineries but the extent of the corrosion is dependent upon the characteristics of the refinery feedstocks and the nature of the processes and the process parameters. When uncorroded steel is exposed to the air (an oxidizing atmosphere), the originally unadulterated (and somewhat shiny) surface of the steel will eventually (depending upon the ambient conditions) be covered with rust (an oxidation product of the iron component of the steel) and the steel is stated to be corroded. Chemically, the tendency of metals to corrode is related to the low stability of the metallic (zerovalent or zero oxidation) state. When metals occur in the form of compounds with other elements (they acquire positive states of oxidation)—such is the case with the formation of iron oxide (rust).

Generally, corrosion of iron in an oxidizing atmosphere is represented as the formation of rust (iron oxide) as might occur on the exterior surfaces of reactors and pipelines (Beavers and Thompson, 2006) which is often represented by the formation of iron oxide and then hydration in humid environments:

$2{\mathrm{Fe}}^0{+\text{3O}}_2\to 2{\mathrm{Fe}}_2{\mathrm{O}}_3$

${\mathrm{2Fe}}_2{\mathrm{O}}_3+x{\mathrm{H}}_2\mathrm{O}\to {\mathrm{2Fe}}_2{\mathrm{O}}_3.x{\mathrm{H}}_2\mathrm{O}$

In reality, rust formation is a much more complex process and can occur at the point of, or at some distance away from, the actual pitting or erosion of iron (Speight, 2014b). The involvement of water accounts for the fact that rust formation occurs much more rapidly in moist conditions than in a dry environment (such as a desert) where water in the atmosphere or water in the ground is limited.

However, acid corrosion does not follow the same type of chemistry and is the deterioration a material undergoes as a result of interactions of the material with the surrounding acidic environment and, in the current context of naphthenic acids, is interior corrosion of the reactor or pipeline (Fontana, 1986; Shreir et al., 1994; Jones, 1996; Peabody, 2001; Bushman, 2002; Landolt, 2007). Although this definition is applicable to any type of material, it is usually reserved for metallic alloys of the types found in industrial settings—such as the petroleum industry. Approximately 80 of the known chemical elements are metals (Speight, 2014b), and approximately half of the metals can be alloyed with other metals, giving rise to several thousand different alloys—many of which are used in refineries. Furthermore, each of the alloys will have different physical, chemical, and mechanical properties, but all of the alloys can corrode to some extent and in different ways due to attack by acidic species. Furthermore, corrosion of an alloy (or metal) influences the chemical properties of the alloy (or metal) and also causes changes in the physical properties and mechanical properties of the alloy which influence behavior and longevity of the alloy as they relate to in-use performance.

2.2 Types of Corrosion

Generally, corrosion can be classified into three general forms based on the type of damage that results and the three general forms are: (1) uniform corrosion, (2) localized corrosion, and (3) stress corrosion cracking. Some types of corrosion damage can be tolerated while other corrosion damage cannot be tolerated and it is important to be aware of these distinctions.

Irrespective of the type of corrosion that occurs, naphthenic acids in crude oil can cause corrosion which often occurs in the same places as high-temperature sulfur attack such as heater tube outlets, transfer lines, column flash zones, and pumps. Furthermore, naphthenic acids alone or in combination with other organic acids (such as phenols) can cause corrosion at temperatures as low as 65°C (150°F) up to 420°C (790°F) (Gorbaty et al., 2001; Kittrell, 2006). Crude oil with a total acid number (TAN) higher than 0.5 mg KOH per gram of crude oil and crude oil fractions with a TAN higher than 0.5 mg KOH per gram of crude oil fractions are considered to be potentially corrosive between the temperature of 230–400°C (450–750°F).

Some other forms of corrosion are galvanic corrosion, selective alloy breakdown, intergranular corrosion, fatigue, friction, erosion, cavitation, hydrogen embrittlement, biocorrosion, and high-temperature oxidation. Since these forms of corrosion have been described in detail elsewhere (Speight, 2014b), only the three general forms of corrosion enumerate above (i.e., uniform corrosion, localized corrosion, and stress corrosion cracking) will be dealt with here.

2.3 Corrosion by Acidic Species

Acid corrosion is typically (but not always) due to the presence of acidic constituents in crude oil. These are the so-called naphthenic acids and various other acidic species that fall within the acid group and which arise as biochemical markers of crude oil origin and various maturation processes (Chapter 1). Naphthenic acid corrosion, which can also include corrosion by other acidic species in the oil, represents an important challenge for the oil refining industry when high acid and/or opportunity crudes (low-quality crude oils) are processed. The corrosivity of low-quality crudes is caused mainly by their natural naphthenic acids (NAP) and sulfur content, which becomes particularly problematic at high-temperature and high-velocity conditions, typical for distilling towers, furnaces, and transfer lines, causing important material losses during processing.

Naphthenic acid is the generic name used for all of the organic acids present in crude oils (Chapter 1)—most of the acids arise as biochemical markers of crude oil origin and maturation (Fan, 1991). Most of these acids are believed to have the chemical formula R(CH₂)_nCOOH, where R is a cyclopentane ring or a cyclohexane ring and n is typically greater than 12. In addition to R(CH₂)_nCOOH, a multitude of other acidic organic constituents are also present in crude oil(s) but, in spite of many claims to the contrary, not all of the species have been fully analyzed and identified and may never by fully identified (never being a long time but is used here to be illustrative of the monumental task required) (Chapter 1) (Blanco and Hopkinson, 1983; Fan, 1991; Babaian-Kibala et al., 1999; Tebbal and Kane, 1996; Tebbal et al., 1997; Tebbal and Kane, 1998; Tebbal, 1999; Dettman et al., 2010).

Naphthenic acid corrosion is one of the well known and serious problems in the petroleum refining industry (Derungs, 1956; Gutzeit, 1977; Slavcheva et al., 1998, 1999; Qu et al., 2005, 2006). The rates of naphthenic acid corrosion do not always increase with an increase in the TAN but do increase with increasing temperature (Chapter 3). In order to obtain the credible corrosion rate, comprehensive analysis and estimation should be performed on the feedstock on the basis of considering not only the temperature but also any other relevant factors (Dettman et al., 2010; Ayello et al., 2011; Wang et al., 2011a). In the petroleum refining industry and the gas processing industry, factors associated with the composition and behavior of the feedstocks (such as temperature, TAN, fluid velocity, gas velocity, and pipeline/reactor material) work simultaneously and cumulatively.

At oil processing temperatures, naphthenic acids show corrosion activity and although there has been numerous works to determine the specific factors, the nature of naphthenic acid corrosion and the factors controlling it are still not completely understood (Kane and Cayard, 1999, 2002; Wu et al., 2004a, 2004b; Flego et al., 2013). There are two major reasons for this general lack of understanding (Kane and Cayard, 1999, 2002; Wu et al., 2004a, 2004b): (1) the extreme complexity and interplay of the factors affecting the corrosion and erosion–corrosion processes such as the different corrosivity of crude oils, depending on the TAN of the crudes as well as the naphthenic acid activity and their distribution over boiling points and decomposition temperatures plus the presence of additional corrosion-active compounds, such as organic sulfur compounds and chlorides, in crude; (2) the variable refining process parameters, such as the hydrocarbon feedstock flow rate, the extent of oil evaporation, and the processing temperature; and (3) the susceptibility of metal equipment to corrosion. The second reason is the lack of laboratory units for effective restored-state experiments mimicking the actual high-temperature and high-feedstock flow rate conditions.

Examples of the variation in the properties of crude oils rich in naphthenic acid species are: Captain, Alba, Gryphon, Harding and Heidrun crudes are all considered opportunity crudes from the North Sea region. The specific gravity of these crudes ranges from 0.88 to 0.94 and the TANs range from 2.0 to 4.1. Gryphon has a sulfur content of 0.4% w/w while Alba has 1.3% w/w sulfur. Such variations require refiners to find high-acid crude oils (HACs) that are suitable for their processing and product profiles—not always an easy task and accurate analysis for estimation of crude oil behavior in the refinery is essential.

Naphthenic acid corrosion is differentiated from sulfidic corrosion by the nature of the corrosion (pitting and impingement) and by the severe (naphthenic acid) corrosion at high velocity in distillation units. Feedstock heaters, furnaces, transfer lines, feed and reflux sections of columns, atmospheric and vacuum columns, heat exchangers, and condensers are among the types of equipment subject to this type of corrosion. Furthermore, isolated deep pits in partially passivated areas and/or impingement attack in essentially passivation-free areas are typical of naphthenic acid corrosion. In many cases, even very highly stable alloys (i.e., 12 Cr, AISI types 316 and 317; AISI is American Iron and Steel Institute) have been found to exhibit sensitivity to corrosion under these conditions.

The acidic species in crude oil can be semiquantified (even pseudo-quantified) by the TAN of the crude oil (Chapter 1) (Scattergood and Strong, 1987; Craig, 1995, 1996; Hau and Mirabal, 1996; Tebbal and Kane, 1996; Lewis et al., 1999; Kane and Cayard, 2002), which is expressed in terms of milligrams of potassium hydroxide per gram (mg KOH/g oil). However, the TAN is not specific to particular acid constituents but refers to all possible acidic components of the oil and is the amount of potassium hydroxide required to neutralize the acids in 1 g of oil; alternatively, the base number can also be used (ASTM D974, ASTM D1386, ASTM D2896, ASTM D3242, ASTM D3339, ASTM D4739, ASTM D5770, ASTM D7253, ASTM D7389).

Although the TAN (Chapter 1) was used to refer to organic naphthenic acids that belonged to the acid group (-CO₂H), other organic acids (such as derivatives of phenol) and mineral acids such as hydrogen sulfide (H₂S), hydrogen cyanide (HCN), and carbon dioxide (CO₂) also contribute significantly to the TAN and hence to the corrosion of equipment. HACs, also called high-total acid number (high-TAN) crude oils, are oils which typically have a TAN in excess of 0.5—this assignment based on the total number acid is arbitrary since corrosivity is crude oil specific and process specific. Nevertheless, processing HACs is also challenging for refineries, especially those not designed to handle crude oil containing naphthenic acids (Heller et al., 1963).

Besides sulfur, crude contains many species that are quantified by the TAN of the oil (Scattergood and Strong, 1987; Craig, 1995, 1996; Hau and Mirabal, 1996; Tebbal and Kane, 1996; Lewis et al., 1999; Kane and Cayard, 2002; Speight, 2009). The TAN number is expressed in terms of milligrams of potassium hydroxide per gram (mg KOH/g) and is not specific to a particular acid but refers to all possible acidic components in the crude and is defined by the amount of potassium hydroxide required to neutralize the acids in 1 g of oil. Typically found are naphthenic acids, which are organic, but also mineral acids such as hydrogen sulfide (H₂S), hydrogen cyanide (HCN), and carbon dioxide (CO₂) can be present, all of which can contribute significantly to corrosion of equipment. Even materials suitable for sour service do not escape damage under such an onslaught of aggressive compounds. Again, because of cost considerations, a trend toward a preference for crude oils with a higher TAN is noticeable.

HACs, also called high-TAN crude oils, are oils which typically have a TAN number in excess of 0.5. HAC trade at discounts of about $3/bbl to $10/bbl to conventional (low acid) crude oils but processing HACs is also challenging for refineries, especially those not designed to handle crude oil containing naphthenic acids (Heller et al., 1963).

Naphthenic acid corrosion is one of the serious long-known problems in the petroleum refining industry (Derungs, 1956; Gutzeit, 1977; Slavcheva et al., 1998, 1999; Qu et al., 2005, 2006). The rates of naphthenic acid corrosion increase with the temperature rising and are also influenced to some extent by the acid content as determined by the TAN. Under the condition of low velocity of naphthenic acid, the influences of fluid velocity on corrosion rate can be detected, especially in the high-temperature conditions. In petroleum refining industry, influence factors (such as temperature, TAN, fluid velocity, and material) work simultaneously. In fact, the TAN is not useful as a characteristic for determining of corrosivity anymore. In this context, methods for the exact analysis of crude oil naphthenic acids are becoming of great importance, as well as revealing the correlation between the configuration and functionality of acids and their corrosivity. Thus, in order to obtain the credible corrosion rate, the comprehensive analysis and estimation should be done on the basis of considering the combining temperature with other factors and not only by the TAN but also the structure of the naphthenic acid constituents as well as sulfur content of the crude oil and other factors related to the reactor parameters (Slavcheva et al., 1998, 1999; Meredith et al., 2000; Laredo et al., 2004).

High-temperature corrosivity of crude oil as illustrated by corrosion in distillation units is a major concern of the refining industry. The presence of naphthenic acid and sulfur compounds considerably increases corrosion in the high-temperature parts of the distillation units and, therefore, equipment failures have become a critical safety and reliability issue.

Isolated deep pits in partially passivated areas and/or impingement attack in essentially passivation-free areas are typical of naphthenic acid corrosion. Damage is in the form of unexpected high corrosion rates on alloys that would normally be expected to resist sulfidic corrosion. In many cases, even very highly alloyed materials (i.e., 12 Cr, AISI types 316 and 317) have been found to exhibit sensitivity to corrosion under these conditions. Naphthenic acid corrosion is differentiated from sulfidic corrosion by the nature of the corrosion (pitting and impingement) and by its severe attack at high velocities in crude distillation units. Crude feedstock heaters, furnaces, transfer lines, feed and reflux sections of columns, atmospheric and vacuum columns, heat exchangers, and condensers are among the types of equipment subject to this type of corrosion.

Crude corrosivity has been loosely associated as a function of the TAN but, among other (unknown) factors, the sulfur content, with particular emphasis on the sulfur type present in the crude oil, also plays a role in crude oil corrosivity. Generally, crude oils that have high acid numbers and low sulfur content are particularly corrosive. In fact, it is possible to develop a series of operating envelopes in terms of TAN and sulfur content (particularly, the corrosive sulfur compounds). For each operating envelope, a specific corrosion control action is required. The economically best option is to run to the limit of a chosen corrosion control level. This approach maximizes the amount of corrosive crude that can be processed for a given level of corrosion control.

Experience has shown that naphthenic crudes generally first affect the vacuum transfer line and VGO side-stream. As feed TAN is further increased, corrosion will affect the atmospheric transfer line and heavy atmospheric gas oil (HAGO) circuits and the bottoms of both towers. Furthermore, while high-acid crudes primarily affect the hot parts of the atmospheric distillation unit and the vacuum distillation unit, they also affect downstream units as well (e.g., hydrotreater preheat trains). Some crude oils have also caused overhead system corrosion because of poor (inefficient) salt removal in the dewatering/desalting unit prior to introduction of the feedstock to the distillation units.

Concurrent presence of both sulfur-containing compounds and naphthenic acids in crudes introduces a new level of complexity into the study of the corrosion mechanisms. Sulfidic corrosion leads to formation of a sulfide scale, which provides some degree of protection against naphthenic acid corrosion.

2.3.1 Chemistry

Corrosion processes caused by the presence of naphthenic acids in the feedstock result in the formation of iron naphthenates in which the acid moieties react with the iron in the metal (or alloy) from which the reactor is constructed:

$\mathrm{Fe}+2\mathrm{RCOOH}\to {\text{Fe}(\text{RCOO})}_2+{\mathrm{H}}_2$ (1)

(1)

${\text{Fe}(\text{RCOO})}_2+{\mathrm{H}}_2\mathrm{S}\to \mathrm{FeS}+2\mathrm{RCOOH}$ (2)

(2)

$\mathrm{Fe}+{\mathrm{H}}_2\mathrm{S}\to \text{FeS}(\text{oil}\text{insoluble})+{\mathrm{H}}_2$ (3)

(3)

The first reaction (Reaction 1) produces the oil-soluble iron (iron naphthenate) and the second reaction inhibits soluble iron production—each reaction is dependent upon the functionality of the sulfur compounds (Meriem-Benziane and Zahloul, 2013). If sulfur is present (as is often the case), the reaction proceeds even further with the formation of iron sulfide (Reaction 2). In short, the amount of sulfur in a crude oil (determined as total sulfur, S% w/w) is not necessarily related to reactivity—for example, hydrogen sulfide is very reactive toward iron, producing a protective layer of iron sulfide (FeS) that can prevent further corrosion by acidic species.

The first reaction (Reaction 1) is the direct attack of naphthenic acid species on the steel lining (low-carbon steel) of columns or reactors and the second reaction (Reaction 2) is responsible for hydrogen sulfide corrosion. Iron naphthenate as a corrosion product is well soluble in oils, and iron sulfide creates a protecting film on the metal surface (Reaction 2). In some instances, this film may not form unless the sulfur content in oil is at least 2—3% w/w (Jayaraman et al., 1986). By Reaction (3), dissolved iron naphthenate interacts with hydrogen sulfide to regenerate naphthenic acids and to produce iron sulfide, which precipitates in the oil thereby affecting its quality. Yépez (2005) considered the influence of sulfur compounds on the processes occurring during naphthenic acid corrosion. It was shown that the inherent presence of these compounds in oils can have directly opposed consequences of NAC: (1) when the system contains sulfur compounds that produce hydrogen sulfide, a protective FeS film is formed on the metal surface (and the further corrosion of metal is stopped); (2) if the system contains sulfoxides, water forms in the cathode zone and the corrosion processes are intensified. The results of the cited study emphasize that it is important to control the presence of sulfoxides in crude oils because these compounds pose a hazard as promoters of petroleum acid corrosion.

Since the iron naphthenates are soluble in crude oil, the surface of the metal is relatively film free. Furthermore, alkali-naphthenates accelerated the naphthenic acid corrosion, and with an increase in the alkali metal atom radius, the corrosion acceleration enhanced. Sodium naphthenates can remove the corrosion product from the metal surface, thus accelerating the corrosion process (Wang et al., 2011a, 2011b).

However, the presence of both naphthenic acids and sulfur-containing compounds in crude oil introduces a new level of complexity into the chemistry of corrosion. Sulfidation corrosion of the metal (typically iron) leads to formation of a metal sulfide (typically iron sulfide) scale, which provides some degree of protection against the onset of naphthenic acid corrosion (Kanukuntla et al., 2008).

In the presence of hydrogen sulfide, a sulfide film is formed which can offer some protection depending on the acid concentration. If the sulfur-containing compounds are reduced to hydrogen sulfide (H₂S), the formation of a potentially protective layer of iron sulfide occurs on the reactor walls and corrosion is reduced (Kane and Cayard, 2002; Yépez, 2005; Bota and Nesic, 2013). When the reduction product is water instead of or as well as hydrogen sulfide, coming from the reduction of sulfoxide derivatives, the naphthenic acid corrosion is enhanced (wet corrosion) (Yépez, 2005).

Furthermore, the accumulation of corrosive hydrogen sulfide in a reactor enhances corrosion as opposed to diminished corrosion in a flow-through reactor. This effect (corrosion by hydrogen sulfide) is aggravated with time and particularly for crude oil that has higher total sulfur content and at higher temperature. In addition, and contrary to early theories, corrosion rates (which are, because of other factors, feedstock dependent) tend to remain constant with increasing TAN until a critical value of the TAN is reached—the so-called critical value is a function of the oil total sulfur content. At higher TANs, the corrosion rate increases sharply marking a transition from sulfidation to naphthenic acid dominated corrosion regime (Kanukuntla et al., 2008).

During high-temperature processes—such as the distillation process during which the temperature of the crude oil in the distillation column can be as high as 400°C—thermal decarboxylation of naphthenic acids can occur:

$\mathrm{R}-{\mathrm{CO}}_2\mathrm{H}\to \mathrm{R}-\mathrm{H}+{\mathrm{CO}}_2$

Carbon dioxide, which is not altogether a noncorrosive material, may show some signs of corrosivity (depending on the conditions when it is formed), and the presence of water in the system results in the formation of carbonic acid, which has enhanced corrosivity over carbon dioxide:

${\mathrm{CO}}_2+{\mathrm{H}}_2\mathrm{O}\to {\mathrm{H}}_2{\mathrm{CO}}_3$

In fact, organic acids, such as acetic acid (CH₃CO₂H), enhance the corrosion rate of mild steel by accelerating a cathodic (electrochemical) reaction (Garsany et al., 2002; Dougherty, 2004; Matos et al., 2010; Amri et al., 2011; Tran et al., 2013; Speight, 2014b). This is the same type of corrosion enhancement that might be expected when naphthenic acids are present, especially when the degradation products of the naphthenic acids are lower molecular weight fatty acids (such as formic acid and acetic acid), which are also corrosive (Gutzeit, 1977). However, the precise chemical aspects of the reaction remain unresolved (some would say controversial), and it is not clear whether the adsorbed acetic acid molecule is reduced at the surface (in addition to any reduction of hydrogen ions) (direct reduction).

The alternative possibility is that the acetic acid dissociates and provides an additional source of hydrogen ions (H⁺) near the steel surface, while the only cathodic reaction is reduction of hydrogen ions, and induces a chemical mechanism referred to as a buffering effect—an effect in which one chemical prevents chemical changes in a chemical system. In some chemical reactions, the buffers are added to the mix or are formed naturally as a result of, or during, the reaction progress.

Such an effect often adds chemical confusion to attempts to assign precise chemistry to the mechanism of corrosion by naphthenic acids, leaving the reaction chemistry somewhat unclear and subject to question. The role played by the degradation products of naphthenic acids is obviously important, and an improved understanding of naphthenic acid corrosion mechanisms will provide a good starting point for a similar analytical approach to be applied to studying related corrosion mechanisms involving carbon dioxide (released by the decarboxylation reaction). In the case of carbon dioxide, it is assumed that the weak carbonic acid (H₂CO₃) either acts as a reservoir of hydrogen ions (giving rise to the buffering effect) and/or can be reduced directly at the steel surface (Hurlen and Gunvaldsen, 1984; Linter and Burstein, 1999; Remita et al., 2008).

Other species in crude oil add complexity to the chemistry of naphthenic acid corrosion. Not all naphthenic acid species in petroleum as determined by the TAN test (Chapter 1) are derivatives of carboxylic acids (COOH), and some of the acidic species (such as phenol derivatives, i.e., derivatives of C₆H₅OH) are resistant to high temperatures. For example, acidic species appear in the vacuum residue after having been subjected to the inlet temperatures of an atmospheric distillation tower and a vacuum distillation tower (Speight and Francisco, 1990; Speight, 2014a). In addition, for the acid species that are volatile, naphthenic acids are most active within the boiling range of the acidic constituents and the most severe corrosion generally occurs at the time of (and shortly thereafter) the condensation of the naphthenic acids from the vapor phase back to the liquid phase.

In addition, petroleum products (especially distillation fractions) are also corrosive. For example, as a general rule, crude oils with an acid number greater than 0.3 to 0.5 mg KOH per gram of crude oil (Chapter 1) and refined crude oil fractions with a TAN higher than 1.5 mg KOH per gram of crude oil fraction have been generally considered to be potentially corrosive due to the presence of naphthenic acid species (Piehl, 1987; Kane and Cayard, 2002). The difference in these two values comes from the concentration of naphthenic acid in specific product fractions produced during the refining process. However, such simple general rules do not always indicate which hydrocarbon fractions and in what locations in the process the concentration of the corrosive acids will occur (Speight and Francisco, 1990). This type of information can potentially result in a better understanding of naphthenic acid corrosivity and help locate potential problem areas in the refinery.

Temperature, metallurgy, TAN, molecular structure, and local flow conditions are known to be important factors affecting naphthenic acid corrosion (Kane and Cayard, 2002; Qu et al., 2007). Metallurgy may not lead to significant differences when it comes to naphthenic acid corrosion. Typically, corrosivity increases significantly with an increase in the TAN above a certain threshold value but at low TAN—under the so-called sulfidation dominated regime—changes in the TAN do not affect naphthenic acid corrosivity, because the corrosion process is controlled by the protectiveness of the iron sulfide scale. The critical TAN value increased for oils with higher total sulfur content (Kanukuntla et al., 2008).

Identification of the chemistry and physics of corrosion allows attempts to be made to prevent corrosion by mitigating the predominant chemical reactions and any associated physical effects (Chapter 5) (Wranglen, 1985; Uhlig and Revie, 1985). Many of the methods for preventing or reducing naphthenic acid corrosion exist, most of them orientated toward removing the naphthenic acids from the feedstock (Chapter 5) or slowing the rates of corrosion (Bradford, 1993; Jones, 1996).

In the former case (i.e., removal of the naphthenic acids from the feedstock), this is the most common approach. In the second case, a series of methods have been developed that are based on depositing a layer of a second material on the surface of a metal structure to impede the structure’s contact with the aggressive naphthenic acids (Speight, 2014b). The most prevalent of these is painting, and a wide range of protective paints is now available and included among these surface covering methods are metallic surface treatments, such as chrome, nickel, and galvanized coatings, and inorganic treatments, such as chromates, anodizing coatings, and phosphate coatings. However, another factor that needs to be considered is the high-temperature stability of the coating—such coatings are not always resistant to degradation at the high temperatures associated with many refinery processing units.

As an alternative to using metals that must be protected by one or other of the methods described, there is also the option of using an alloy selected for having a greater resistance to corrosion caused by its surroundings. However, alloys with good resistance in one environment may have poor resistance in another, and their resistance is also likely to vary according to differences in exposure conditions, such as temperature or stress.

Another method of protection uses chemical inhibitors, which are substances added to the liquid medium, again to reduce rates of corrosion (Chapter 5) (Speight, 2014b).

2.4 Sulfidic Corrosion

The issue of sulfidic corrosion in refineries is of great importance when considering naphthenic acid corrosion. The presence of sulfur in crude oil can/will enhance the corrosive effects of naphthenic acids in the same oil.

Other than carbon and hydrogen, sulfur is the most abundant element in petroleum. It may be present as elemental sulfur, hydrogen sulfide, mercaptans, sulfides, and polysulfides. Sulfur at a level of 0.2% and greater is known to be corrosive to carbon and low-alloy steels at temperatures from 230°C to 455°C (450–850°F). One reason why sulfidic corrosion (sulfidation) is receiving much more emphasis is the increased processing of low-quality sour (high-sulfur) crude oils, which often contain naphthenic acids.

Sour crude is crude oil with high sulfur content (as opposed to low sulfur content sweet crude). Although sour crude oil is available at a lower cost and may be preferable to refineries, low-sulfur (sweet) crude oil is becoming less readily available as the bulk of its supply is exhausted. In sour crude, sulfur is present in the form of mercaptans (RSH), hydrogen sulfide (H₂S), sulfide salts, and a variety of other sulfur-containing constituents (Speight and Ozum, 2002; Hsu and Robinson, 2006; Gary et al., 2007; Speight, 2014a). Sulfur may be present as elemental sulfur (S), hydrogen sulfide (H₂S), mercaptans (RSH), sulfides (SR), and polysulfides (RS_nR).

Sulfur in crude oil at levels greater than 0.2% w/w is been found to be corrosive to carbon steel and also to low-alloy steel at temperatures on the order of 230–455°C (450–850°F) (Backensto et al., 1956; Hucińska, 2006). This is often the result of partial conversion of sulfur constituents to hydrogen sulfide during atmospheric distillation. Usually this form of sulfur corrosion can be handled adequately with steel alloys (5–9% w/w Cr–Mo) unless the crude oil also contains naphthenic acids for which Type 316 or Type 317 stainless steel is preferred. Typically, the most important internal or metallurgical factor to control sulfidic corrosion is the amount of chromium in the steel. The refinery industry relies today in a vast industrial experience on the variables affecting sulfidic corrosion but very little is known on the basic mechanism of attack (Rebak, 2011).

Sulfidic corrosion (sometime referred to as sulfidation or sulfidization) is differentiated from naphthenic acid corrosion by the corrosion mechanism and the form and structure of the corrosion. While naphthenic acid corrosion is typically characterized as having more localized attack particularly at areas of high velocity and, in some cases, where condensation of concentrated acid vapors can occur in crude distillation units, sulfidic corrosion typically takes the form of a general mass loss or wastage of the exposed surface with the formation of a sulfide corrosion scale.

In addition, the particular forms of sulfur that can participate in this process and the mechanism by which sulfidic corrosion can be understood involves the realization that both sulfur and acid species are present to a varying degree in all crude oils and fractions. In certain limited amounts, sulfur compounds may provide a limited degree of protection from corrosion with the formation of pseudo-passivity sulfide films on the metal surfaces. However, increases in either reactive sulfur species or naphthenic acids to levels beyond their threshold limits for various alloys may accelerate corrosion (Kane and Cayard, 2002).

Sulfidation of metals is subject to (1) exposure time, (2) partial pressure of hydrogen, (3) partial pressure of hydrogen sulfide, (4) temperature, especially to temperatures above 200°C (390°F), and (5) gases containing hydrogen sulfide. Examples of the types of process equipment where sulfidation is a concern are (1) distillation columns, (2) vacuum columns and flashers, (3) coking units, (4) hydrotreater charge furnaces, (5) and sulfur removal plants (gas sweetening plants). Common methods to confirm that sulfidation has occurred are either X-ray diffraction analysis of the surface scale or analysis of the gas composition.

Sulfidation can occur upon exposure of metals to temperatures above approximately 200°C (390°F) in gases containing hydrogen sulfide at extremely low particle pressure. Examples of the types of process equipment where sulfidation is a concern are hydrotreater charge furnaces, crude distilling columns, vacuum flashers, petroleum coking units, and sulfur removal plants (gas sweetening plants). The presence of sulfides confirms sulfidation, which occurs when metals are exposed to gases containing hydrogen sulfide and carbonyl sulfide (COS), and variable process parameters that influence the sulfidation rate are (1) the exposure time, (2) the partial pressure of hydrogen sulfide, and (3) the temperature.

This situation is not expected to improve soon because of the increased processing of low-quality, high-acid, sour (sulfur containing) crude oils. Because it provides a lower feedstock cost (discounted cost) (Chapter 1), such crude oils are preferred by refineries for economic reasons. Furthermore, sweet (low sulfur, low acid) crude oil is becoming less readily available as the bulk of its supply is exhausted. In sour crude, sulfur is present in the form of mercaptans, hydrogen sulfide (H₂S), sulfide salts, and a variety of other sulfur-containing constituents (Hsu and Robinson, 2006; Gary et al., 2007; Speight, 2014a). Many of these species are reactive and combine with naphthenic acids constituents to cause corrosion, leading to stress cracking and sulfuric acid corrosion in other units throughout the refinery.

Sulfidic corrosion of steels in refineries is a prevalent phenomenon that occurs in oil-containing sulfur species between 230°C and 425°C. There are several internal and external variables controlling the occurrence of sulfidic corrosion. The most important external factors are temperature, concentration and type of sulfur species, and presence of naphthenic acid. The most important internal or metallurgical factor to control sulfidic corrosion is the amount of chromium in the steel. The refinery industry relies today in a vast industrial experience on the variables affecting sulfidic corrosion but very little is known on the basic mechanism of attack (Rebak, 2011).

Boilers generating steam for use in power generation and process power plants use different type of fuels—varying from coke to heavy oil (Speight, 2013a, 2013b, 2014a). In such cases, the presence of naphthenic acids may not be too alarming but the higher the percentage of sulfur, the higher will be the risk of cold-end corrosion in the boiler. The sulfur in the fuel during combustion gets converted to sulfur dioxide. Depending upon the other impurities present in the fuel and excess air levels, some portion of the sulfur dioxide is converted to sulfur trioxide. Because of the presence of moisture in the flue gas (due to moisture in fuel and air), sulfur dioxide and trioxide forms sulfuric acid. These acids condense over the range 115–160°C (240–320°F), depending upon the concentration of sulfur trioxide and water vapor and leading to the formation of the acid species:

$\mathrm{S}+{\mathrm{O}}_2\to {\mathrm{SO}}_2$

${\mathrm{SO}}_2+{\mathrm{O}}_2\leftrightarrow {\mathrm{SO}}_3$

${\mathrm{H}}_2\mathrm{O}+{\mathrm{SO}}_2\leftrightarrow {\mathrm{H}}_2{\mathrm{SO}}_3$

${\mathrm{H}}_2\mathrm{O}+{\mathrm{SO}}_3\to {\mathrm{H}}_2{\mathrm{SO}}_4$

Depending upon the concentration of sulfur trioxide and water vapor, the dew point temperature can vary from approximately 90°C to 140°C (195–285°F).

Condensation of these acids results in metal wastage and boiler tube failure, air preheater corrosion, and flue gas duct corrosion. In order to avoid or reduce the cold-end corrosion, the gas temperature leaving the heat transfer surface in boiler is kept at approximately 150°C (300°F) but within the range 120–155°C (250–310°F). It is very important that the metal temperature of the tubes is always kept above the condensation temperature. It may be noted that the metal temperature of the tubes is governed by the medium temperature of the fluid inside the tubes. This makes it necessary to preheat water to at least 150°C (300°F) before it enters the economizer surface. In the case of an air preheater, two methods are used to increase the metal temperature. One is an air bypass for air preheater, and the second is using a steam coil air preheater to increase the air temperature entering the air preheater.

The amount of sulfur trioxide (SO₃) produced in boiler flue gas increases with an increase of excess air, gas temperature, residence time available, the amount of catalysts such as vanadium pentoxide (V₂O₅), nickel (Ni), ferric oxide (Fe₂O₃), and the sulfur level in crude oil or the boiler fuel. In addition, and depending upon the concentration of the sulfur trioxide and water vapor concentration, the dew point temperature can vary from approximately 90°C to 140°C (195–285°F)—this is the temperature below which water vapor in air at constant barometric pressure condenses into liquid water at the same rate at which it evaporates. The condensed water (dew) forms on a solid (metal) surface and is acidic.

In order to avoid or reduce the cold-end corrosion, the gas temperature leaving the heat transfer surface in the boiler is kept at approximately 150°C (300°F) but within the range 120–155°C (250–310°F). It is very important that the metal temperature of the tubes is always kept above the condensation (dew point) temperature. However, the temperature of the metal tubes is governed by the temperature of the fluid inside the tubes—this requires that the water is preheated to at least 150°C (300°F) before it enters boiler tubes. In the case of an air preheater, two methods are used to increase the metal temperature: (1) an air bypass for the air preheater and (2) use of a steam coil air preheater to increase the air temperature entering the air preheater.

2.5 Physical Effects

Naphthenic corrosion is an aggressive form of local corrosion related to the processing of acidic crude oil (Chapter 1). The typical naphthenic corrosion is observed in the temperature interval 200–400°C (390–750°F). Generally, the corrosion rate increases thrice per each 55°C (99°F) increase of temperature over this temperature range, and it has been suggested that the corrosion is limited within the zones where the condensing acids could contact with metal surface (e.g., lower part of the plates), that is, where the protective layer of hydrocarbons diluting the acids is missing (Petkova et al., 2009).

2.5.2 Effect of Temperature

Wherever the location, many refineries share similar problems, such as: (1) aging equipment, (2) high costs of replacement, and (3) the need to produce more efficiently while being increasingly concerned with issues of safety and reliability. For equipment operating at various temperatures, especially at high temperature, there are many different mechanisms of corrosion damage, some of which are interactive. In addition, the rate of accumulation of the damage is not always easy to predict, especially when high temperature plays a role in the corrosion process.

When metal is exposed to an oxidizing gas at elevated temperature, corrosion can occur by direct reaction with the gas without the need for the presence of a liquid phase (electrolyte). This type of corrosion is referred to as high-temperature oxidation, scaling, or tarnishing and increases substantially with temperature. In the refinery and gas processing plant scenario, the rate of most reactions leading to corrosion, as with the rate of chemical reactions in general, increases with increasing temperature, approximating to a doubling of the reaction rate for each 10°C (18°F) rise in temperature whether the corrosion process involves dissolution leading to general attack or to a more localized form such as cracking. In general, therefore, lower temperatures will be more beneficial, but there are exceptions.

High-temperature crude corrosivity of distillation units (due to the presence of naphthenic acids in the feedstock) is a major concern of the refining industry (Craig, 1996; Wang et al., 2011a). Naphthenic acid corrosion occurs primarily in high-velocity areas of crude distillation units in the 220–400°C (430–750°F) temperature range. No corrosion damage is usually found at temperatures greater than 400°C (750°F), probably due to the decomposition of naphthenic acids or protection of the metal from the coke formed on the metal surface.

The presence of naphthenic acid and sulfur compounds considerably increases corrosion in the high-temperature parts of the distillation units, and therefore, equipment failures have become a critical safety and reliability issue. In addition to acidic corrosion, the presence of naphthenic acids may increase the severity of sulfidic corrosion at high temperatures, especially in furnaces and transfer lines. The presence of naphthenic acids can disrupt the sulfide film, thereby promoting sulfidic corrosion on alloys (such as 12 Cr and higher alloys) that would normally be expected to resist this form of attack. In some cases, such as in side-cut piping, the metal sulfide film produced from hydrogen sulfide is believed to offer some degree of protection from naphthenic acid corrosion.

In the refining and gas processing industries, the influence of factors (such as temperature, TAN, fluid velocity, and material) tend to work simultaneously and cumulatively, and in order to obtain credible (low) rates of corrosion, comprehensive analysis and estimation of the propensity for corrosion should be performed on the basis of consideration of temperature and other relevant factors.

In summary, the relationship between temperature and corrosion rate at a constant TAN generally exhibits a linear relationship. Naphthenic acid corrosion is normally not a concern much below 200°C (390°F). As temperature increases, the corrosion rate may increase until the temperature is sufficiently high to decompose the complex higher molecular weight naphthenic acids to lower molecular weight organic acids. The differential between TAN and the naphthenic acid titration number then begins to widen with the naphthenic acid titration number decreasing—this phenomenon usually occurs at temperatures in excess of 420°C (790°F), where the decomposition of the organic species in petroleum occurs at an ever-increasing rate (Speight, 2014a).

High-temperature corrosion is not limited to only naphthenic acid corrosion in the distillation units and can also occur by carburization or sulfidation. Carburization takes place in carbon-rich atmospheres such as in reformer or other (high-temperature) furnaces, and the surface layer of the alloy can become brittle, leading to the formation of cracks, particularly when there are severe or cyclic temperature changes, which can greatly reduce the strength of the component. Sulfidation can be a serious problem in nickel-based super alloys and austenitic stainless steels, with sulfides also forming on grain boundaries and then being progressively oxidized and causing embrittlement in the alloy.

Oxidation is the most commonly encountered form of high-temperature corrosion but may not always be detrimental. In fact, most corrosion- and heat-resistant alloys rely on the formation of an oxide film to provide corrosion resistance. Chromium oxide (chromia, Cr₂O₃) is the most common of such films. However, as the temperature is increased, the rate of oxidation increases and becomes deleterious. Increased chromium content is the most common way of mitigating or at least improving the oxidation resistance of alloys.

While minimization of corrosion in alloys for high-temperature applications depends on the formation of a protective oxide scale, for alloys with very high strength properties at high temperature, a protective coating may need to be applied. The oxides that are generally used to provide protective layers are chromia (Cr₂O₃) and alumina (Al₂O₃). Corrosion protection usually breaks down through mechanical failure of the protective layer, which involves spalling of the oxide (production of flakes produced by a variety of mechanisms, including as a result of projectile impact, corrosion, weathering, or cavitation) as a result of thermal cycling or from erosion or impact.

Thus, naphthenic acid corrosion and high-temperature crude corrosivity in general become a reliability issue in refinery distillation units (Chapter 5). Refinery corrosion occurs at temperatures between 220°C (430°F) and 400°C (750°F). In this temperature range, naphthenic (organic) acids (RCOOH) reach their boiling points and condense on metal surfaces, removing iron [Fe] and eventually causing pits. There may also be decarboxylation and the carbon dioxide that is formed also has the potential to cause corrosion. However, corrosivity does not always correlate with TAN (Derungs, 1956; Zetlmeisl et al., 2000; Messer et al., 2004). Thus, there is the possibility that other organic acid species in some crude oil contribute to corrosion.

Reactive sulfur content of the various side-cut oils also requires investigation as this can lead to strategies for inhibiting the possibility of naphthenic acid attack (with possible decreased corrosion rate). Higher sulfur level is generally considered to be beneficial for the inhibition of naphthenic acid attack. However, increased concentrations of reactive sulfur may trigger high-temperature sulfur-based corrosion. It is important to note that traditional metallurgies resistant to high-temperature sulfidic corrosion are not very resistant to high-temperature naphthenic acid corrosion attack.

The combined presence of naphthenic acid and sulfur compounds considerably increases corrosion in the high-temperature parts of the distillation units. Sulfur-containing compounds decompose to form hydrogen sulfide (H₂S), where iron removal causes general corrosion but can form protective films. Acidic complements of the feedstocks and hydrogen sulfide are often chemically complementary in terms of corrosivity:

$\mathrm{Fe}+2\mathrm{RCOOH}\to {\text{Fe}(\text{RCOO})}_2(\mathrm{oil\; soluble})+{\mathrm{H}}_2$

In fact, the ability to predict corrosion behavior has been difficult, and the accepted chemistry that organic acid corrosion, that corrosivity correlates with TAN, is inadequate for predicting refinery corrosion due to its assumption that all acid molecules are equally corrosive regardless of their composition and structure (Zetlmeisl et al., 2000).

Furthermore, the difference in process conditions, materials of construction, and blend processed in each refinery and especially the frequent variation in crude diet increases the problem of correlating corrosion of a unit to a certain type of crude oil. In addition, crude oil composition from the same field can change with time. When steam flooding or other recovery methods begin in an oil field, the specific gravity and the organic and sulfur content of the crude may change. For example, fire flooding, when used in some fields, tends to increase the naphthenic acid content.

There are at least three mechanisms of naphthenic acid corrosion. Each one is predominant in specific areas of the distillation unit (Chapter 3).