Keywords

Petroleum acids; corrosion; refinery equipment; processing; naphthenic acids; carboxylic acids; phenols

3.1 Introduction

The trend in crude oil supplies by refineries is towards heavier, lower quality feedstocks—the ratio of heavy crude oil (API 10–20°) in the total crude oil slate continues to rise, often in an apparent accelerated pace (Speight, 2014a). Thus, the oil refining industry must increasingly face the challenges presented by heavy, low quality crudes, cleaner production standards, and the demand for cleaner fuels and high-value petrochemical products.

Opportunity crude oil generally refers to crude oils with relatively high metals and sulfur content, and a high total acid number (TAN) and density (see Chapter 1). High acid content in heavy crude oil is the typical opportunity crude oil and the following properties are general: (i) fewer low boiling components, (ii) high density, (iii) low viscosity, (iv) high metal contents, (v) high asphaltene content, and (vi) high acid number, which give rise to equipment corrosion and severe problems with product quality and environmental protection.

The growing variety of discounted opportunity crudes on the market usually contains one or more risks for the purchaser, such as high naphthenic acid content. As the availability and volume of highly naphthenic crudes processed increase, the risk of experiencing high temperature corrosion on refinery equipment must be considered. In fact, many opportunity crudes are known to contain naphthenic acids (NAP), which can cause corrosion in high temperature regions within the refinery, normally around the crude and vacuum towers. These opportunity crudes, also known as high acid crude oils, are often discounted due to the added risks associated with processing these crudes. Because of the economic advantages, many refiners are looking increasingly at processing high levels of naphthenic crude oils in their crude slates.

NAP have been identified as the main corrosive species in acidic crudes although they represent <4% (w/w) of the crude oil (see Chapter 1) (Dzidic et al., 1988; Fan, 1991; Hsu et al., 2000; Laredo et al., 2004).

Naphthenic acids in petroleum (NAP) are corrosive at high temperatures and the lower temperature limit when petroleum naphthenic acids become corrosive is 220°C (430°F) (Derungs, 1956). The corrosive effects of petroleum naphthenic acids are intense at a temperature range between 220°C (430°F) and 400°C (750°F) (Heller et al., 1963; Slater et al., 1974; Gutzeit, 1976a, b, 1977; Morrison et al., 1992; Babaian-Kibala et al., 1993a,b; Craig, 1995, 1996; Slavcheva et al., 1998; Turnbull et al., 1998). There are also two methods developed by UOP (UOP Method 565-92, UOP Method 587-92) in which the sulfur is first removed before determining the acid number. This negates any effects of acid sulfur compounds on the TAN.

The TAN has been used to distinguish the acidity of crude oil: acidic crude oil has an acid number >0.5 mg KOH/g and high acid crude typically has an acid number >1.0 mg KOH/g, although this number is subject to other factors that render it of questionable value (see Chapter 1). For high acid crude, there are two main types that are designated according to sulfur content: (i) high TAN low sulfur heavy crude and (ii) high TAN high sulfur heavy crude. The latter is produced in Venezuela and California, while high acid low sulfur heavy crudes are more common and there are oil fields in four continents producing this type of crude, which is processed by refineries in Europe and the Gulf of Mexico. In the Americas, the high acid low sulfur heavy crudes are mainly represented by the Marlim crude oil (Campos Basin, Brazil) and are processed in several continents. In Africa, the high acid low sulfur heavy crudes are mainly represented by West African Kuito crude oil and Sultan crude oil, which are processed in refineries in the United States and Asia. In Asia, high acid low sulfur heavy crudes are mainly represented by crudes such as Penglai crude oil (Bohai Bay, China), which is processed mainly in China.

3.2 Process Effects

Because of their economic attractiveness, there is widespread interest in processing corrosive crudes, particularly those with high TAN. Many refiners have conducted studies to assess the amount of corrosive crude that can be processed with their existing equipment (i.e., without changing its metallurgy). Also, they must often determine the extent to which their equipment and piping construction materials must be upgraded in order to be able to process the desired crude.

However, the properties of crude oils rich in naphthenic acid species vary and no single approach is best for all sites—the answer is different for each site. For example, Captain, Alba, Gryphon, Harding, and Heidrun are all considered opportunity crudes from the North Sea region. The specific gravity of these crudes ranges from 0.88 to 0.94 and acid numbers range from 2.0 to 4.1. The Gryphon has a sulfur content of 0.4 wt% while Alba crude oil contains 1.3% (w/w) sulfur. These variations allow refiners to find high acid crude oils that are suitable for their product profile. In addition, North Sea Captain crude oil has a whole crude TAN of 2.5 and a naphthenic acid titration number of 2.2, yet the lowest boiling fraction (lightest cut) only has a TAN of 0.25 and a naphthenic acid titration number of 0.3. As higher boiling fractions (heavier cuts) are tested, the TAN and the naphthenic acid levels increase to a high TAN of 3.8 and naphthenic acid titration number of 2.6 in the 390–480°C (735–900°F) cut.

NAP cause several problems during refining and from an operational point of view, producing and processing highly acidic crudes involve a number of challenges. Corrosion by NAP, especially in the high temperature parts of the distillation units, is a major concern to the refining industry (Piehl, 1988; Babaian-Kibala et al., 1993a,b; Slavcheva et al., 1998, 1999). In addition and prior to entering the refinery, there are also problems that arise during production of high acid crudes—the amphiphilic NAP may also accumulate at interfaces and stabilize water-in-oil emulsions causing enhanced separation problems (Pathak and Kumar, 1995; Acevedo et al., 1999; Goldszal et al., 2002; Ese and Kilpatrick, 2004). Pressure drop during fluid transportation from the reservoir to the topside leads to release of carbon dioxide and to a subsequent increase in the pH of the coproduced water, which brings about a higher degree of dissociation of NAP at the oil–water interface. The dissociated moieties may thus react with metal cations in the water to form metal naphthenates. Due to low interfacial affinity and low solubility in water, especially when multivalent cations are involved, the naphthenates will precipitate and start to agglomerate in the oil phase. As the density of the precipitate lies between that of oil and water, it will gradually settle and accumulate at the oil–water interface and further adhere to process unit surfaces. Deposition of metal naphthenates (see Chapter 1) is a problem predominantly in topside facilities like oil–water separators and desalters, and may lead to difficulties in desalting leading to costly shutdowns.

Many refiners have opted to install high alloy equipment and piping systems that are resistant to corrosion by naphthenic acids. While effective, this approach is only economically attractive if a secure long-term supply of corrosive crude is available at attractive prices. Money spent on alloy material can only be recovered by processing corrosive crudes at a good margin. Experience has shown that the most effective approach is to establish a series of limits on TAN (or neutralization number) that are related to progressive corrosion control actions. Preferred corrosion control actions include the following: (i) use of a naphthenic acid corrosion (NAC) inhibitor, (ii) focused inspection and corrosion monitoring, and (iii) limited alloy upgrading.

The advantage of this approach is that inhibitor injection can be discontinued and monitoring can be reduced when high TAN crude is not available. This reduces the total cost for the program.

Crude oil corrosivity is a function of the TAN and sulfur content, amongst other parameters. Crude oils that have a high TAN and low sulfur are particularly corrosive. It is not always possible to develop a series of operating envelopes in terms of TAN and sulfur (i.e., 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 oil that can be processed for a specific level of corrosion control.

Experience has shown that naphthenic acid crude oil feedstocks generally first affect the vacuum transfer line and vacuum gas oil (VGO) side stream (Figure 3.1). As the 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.

NAC is complicated not least because of the complexity of the mixture of naphthenic acid compounds found in crude oils from the various sources. Sometimes, the distribution of NAP is grouped according to their boiling point, with an implication that NAP with different boiling points lead to different corrosivity. Concurrent presence of both sulfur containing compounds and NAP in crudes introduces a new level of complexity into the study of the corrosion mechanisms. Sulfidation corrosion leads to formation of a sulfide scale, which provides some degree of protection against NAC; however, this subject has been given relatively little systematic attention in the past.

In order to process high acid crude oils, it is necessary to use a series of steps based on reliable background information which will provide an approach to evaluating processing options for high acid number corrosive crude oils and will allow development of corrosion mitigation methodologies for high acid corrosive crude oils.

For example, data on the materials of construction and the condition of equipment and piping systems should be collected and analyzed—the data should include information about fired heaters, transfer lines, lower tower, lower side streams, and bottoms of the atmospheric distillation unit and the vacuum distillation unit. Also, it is necessary to summarize any current corrosion control programs and their results for atmospheric distillation overhead system as well as the performance of the desalting operation. Moreover, the records of the past crude slate and performance properties of each crude oil (especially the properties of crude oil blends) should be summarized and used as back-up data to be evaluated as may be applied to future crude slates.

It is also necessary to determine the predicted equipment life for both the current crude slate and future crude feedstock options, which must also include any limits on the lifetime of equipment and piping that would be affected by corrosion. As part of this exercise, there should also be an investigation of the TANs and sulfur content that would affect equipment and piping performance that will permit acceptable run lengths. Actions to enhance equipment and piping performance should also be identified and any incremental increases in the TAN of the feedstock should be identified and the influence on equipment and piping estimated.

A most important aspect of this work is to develop a monitoring and inspection program which is practical and which will allow the predicted limits to be optimized. As part of this monitoring program, it is essential to define the baseline monitoring to be carried out before an increase in the TAN of the feedstock as well as to establish review intervals for the overall program. As part of corrosion mitigation, determine the most attractive combination of inspection, inhibition, and limited alloy upgrading for several levels of TAN of the feedstock. Some high acid crude oils perform poorly in the desalting operation and the result is increased rates of fouling in preheat equipment. Monitoring programs to assess the impact of these issues must also be developed as part of the study.

In summary, processing high acid crude oils is subject to the following criteria as they relate to corrosivity: (i) temperature, (ii) NAP concentrate in fractions boiling above 230°C (450°F), (iii) the highest concentration of NAP is typically found in the 315–425°C (600–800°F) boiling range, (iv) the lowest temperature where attack occurs is approximately 200°C (390°F), (v) lower molecular weight acids—lower boiling acids such as formic acid and acetic acid—occur at water condensing locations, (vi) at low velocity, turbulence caused by boiling and condensing causes attack, and (vii) at high velocity, rapid corrosion can occur. These criteria are reasonably well defined for conventional crude oil but are somewhat less well defined for heavy crude oil and tar sand bitumen.

3.3 Corrosion of Refinery Equipment

The corrosion of refinery equipment during oil distillation was observed during the early part of the twentieth century (Jayaraman et al., 1986). As the oil refining industry evolved toward the modern industry, the problem of corrosion increased and became a serious aspect of equipment performance that needed constant attention (Lewis et al., 1999; Johnson et al., 2003a,b). Experience has shown that the main sites of corrosion attack are the components of oil pumping and refinery transfer lines, such as pipelines, valves and gates, heat exchangers, pipe stills, bubble sections, hydrocarbon stock feeders, and fractionating tower reflex units. Accidents related to corrosion processes resulted in equipment outage and economic losses, thus making it necessary to investigate the causes of this type of corrosion. Petroleum naphthenic acids (PNA) present in crude oils produced in many world regions are considered now to be the main factor responsible for the corrosion problem (Gutzeit, 1976a, b, 1977; Jayaraman et al., 1986; Babaian-Kibala et al., 1993a,b; Turnbull et al., 1994; Slavcheva et al., 1998, 1999).

As oil processing temperatures increase, NAP exhibit significant corrosivity, inducing the specific corrosion type termed NAC. The nature of this type of corrosion and the factors controlling it are still incompletely understood (Zetlmeisl, 1996). Therefore, despite the numerous efforts to prevent or mitigate corrosion made in the last several decades, the problem of corrosion remains acute and ever-present. It is noted that there are two reasons behind this situation: the extreme complexity and interplay of the factors affecting the corrosion and erosion–corrosion processes. These factors are: (i) different corrosivity of crude oils, depending on the total add number (TAN) of the crudes, the activity of PNA and their distribution over boiling points and decomposition temperatures, and the presence of additional corrosion-active compounds, such as organic sulfur compounds and chlorides in crude; (ii) the variable oil refining parameters, such as the hydrocarbon feedstock flow rate, the extent of oil evaporation, and the processing temperature; and (iii) 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. The situation in oil refining has been aggravated in recent years by the progressively increasing involvement of crude oils with a high acid content (Kane and Cayard, 1999).

The issues of NAC have been the subject of many investigations throughout the world; countries such as China, India, Venezuela, Western Europe, Russia, the United States, and Middle Eastern countries have put considerable effort into understanding the mechanism of corrosion with the goal of mitigating damage to refinery equipment (Jayaraman et al., 1986). Earlier, it was believed that this type of corrosion, which is especially intense at high temperatures, is caused by the presence of NAP or sulfur containing constituents of crude oil but researchers failed to distinguish between these factors. Now it is known that the naphthenic acid content is, in principle, related to (i) the TAN of the crude oil system, (ii) the process temperature, and (iii) the flow rate (see Chapters 1 and 2) (Jayaraman et al., 1986; Babaian-Kibala et al., 1993a,b).

However, the TAN is, at best, a rough estimate of the corrosivity of crude oil and it provides investigators only with the general information that oils with a high TAN (0.3 mg KOH/g oil) are already corrosive and does not give accurate information about the extent of the anticipated corrosion. Indeed, there are data that oils with a relatively low TAN are comparable in the corrosivity index with those with a high TAN. Furthermore, crude oil with a high TAN turned out to be less aggressive than could be expected on the basis of the TAN. For example, Indonesian light crude with a TAN <0.5 mg KOH/g and Nigerian crude oil with a TAN 0.3 mg KOH/g and a sulfur content of 0.24% (w/w) causes significant corrosion although the respective TANs do not suggest such a difference in corrosivity (see Chapter 1) (Jayaraman-Kabila et al., 1986; Slavcheva et al., 1999).

Furthermore, it is now generally accepted crude oils having identical TANs differ substantially in corrosivity and, thus, evaluation of crude oil corrosivity in terms of the TAN is insufficient (Turnbull et al., 1994; Slavcheva et al., 1998). A natural explanation offered for these findings is that corrosion is controlled by the type, structure, and functionality of PNA, rather than the TAN value (Qu et al., 2007).

NAC is especially intense at oil distillation temperatures of 220–400°C (430–750°F) and high fluid flow rates. The presence of sulfur promotes naphthenic acid corrosivity owing to the following concurrent reactions (see Chapter 2):

$\mathrm{Fe}+\mathrm{RCOOH}\to {\text{Fe}(\text{RCOO})}_2+{\mathrm{H}}_2$ (3.1)

(3.1)

$\mathrm{Fe}+{\mathrm{H}}_2\mathrm{S}\to \mathrm{FeS}+{\mathrm{H}}_2$ (3.2)

(3.2)

$\mathrm{Fe}{(\mathrm{RCOO})}_2+{\mathrm{H}}_2\mathrm{S}\to \mathrm{FeS}+\mathrm{2RCOOH}$ (3.3)

(3.3)

Reaction (1) illustrates the direct attack of NAP on the steel lining of columns (low-carbon steel) while Reaction (2) is responsible for hydrogen sulfide corrosion. Iron naphthenate as a corrosion product is well soluble in oils, and iron sulfide creates 11 protecting films on the metal surface via Reaction (2). This type of film does 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 the naphthenic acid(s) and to produce iron sulfide (FeS), which precipitates in the oil and thereby affecting the quality of the oil.

Investigations of the influence of sulfur compounds on the chemical and physical processes occurring during NAC have shown that the inherent presence of certain sulfur compounds in crude oil can have diametrically opposed consequences of NAC. For example, (i) when the system contains sulfur compounds that produce hydrogen sulfide, a protective iron sulfide (FeS) film is formed on the metal surface and the further corrosion of metal is lessened – if not stopped – depending on the extent of the coverage of the metal by the film, or (ii) if the system contains sulfoxides—oxidation products of the sulfur constituents of crude oil—water forms in the chemical cathode zone and the corrosion processes are intensified (Yépez, 2005).

These observations 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.

Attempts to draw a correlation between the TAN, sulfur content, and the corrosion activity of crude oil and light and heavy VGOs have shown that there is a good correlation between the TAN and corrosivity only for desalted (demineralized) samples of a 90/10 Isthmus/Maya crude blend (Laredo et al., 2004). For the same fractions, no correlation between the decree of corrosion and the sulfur content was found. The mass spectra of crude samples indicate that the naphthenic acid composition (simple or complex) has no direct effect on the TAN or the corrosivity of tile acids.

It has also been noted (Turnbull et al., 1994; Slavcheva et al., 1998, 1999) that in light of recent studies, the TAN criterion is not useful as a characteristic of corrosivity anymore. In this context, methods for the exact analysis of naphthenic acid structure are becoming of great importance, as well as revealing the correlation between the configuration and functionality of NAP and the corrosivity (Qu et al., 2007). Mass spectrometry, which is widely used for analyzing complex hydrocarbon mixtures, fuel and oil composition (Speight, 2001, 2002, 2014a) and identifying the naphthenic acid structure, is considered to be the most effective and authentic technique. Various hybrid techniques which are versions of mass spectrometry coupled with another method are also in use. The basic difficulty met by researchers in the application of any of these techniques is that of selective isolation of NAP from oil samples, since the mass spectra of the NAP are complex, superimposed, and poorly readable. Researchers also need to consider the three-dimensional electronic structure of the NAP as this most likely will offer more valuable information about the corrosion mechanism.

The corrosivity of oil fractions and the means of its prevention were studied. Kerosene: free of acid components and phosphoric acid esters were tested as corrosion inhibitors. The efficiency of inhibitors was determined on special plates in atmospheric vacuum distillation columns by measuring the electrical resistance of samples. Kerosene showed the highest anticorrosive efficiency at a volume ratio of 1:3. Phosphate inhibitors at a 100 ppm concentration preclude corrosion by almost 100%.

3.4 Interaction of Acids with Refinery Equipment

NAP in crude oil 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 (Shalaby, 2005 and references cited therein). Furthermore, NAP alone or in combination with other organic acids, such as phenols, can cause corrosion at temperatures as low as 65°C (150°F) and as high as 420°C (790°F) (Gorbaty et al., 2001; Kittrell, 2006). Crude oils with a TAN higher than 0.5 and crude oil fractions with a TAN higher than 1.5 are considered to be potentially corrosive between the temperature of 230–400°C (450–750°F).

Corrosion by NAP typically has a localized pattern, particularly at areas of high velocity and, in some cases, where condensation of concentrated acid vapors can occur in crude distillation units. The upper head of distillation columns at refineries is in general strongly affected by corrosion. The corrosion reduces the service life of the equipment and creates economic problems for oil refiners. The basic classes of corrosion inhibitors used to prevent the corrosion of fractionation column heads, the criteria for selection of corrosion inhibitors for other industrial units, and the basic aspects of design of the injection system for these inhibitors are considered.. Damage is in the form of unexpected high corrosion rates on alloys that would normally be expected to resist sulfidic corrosion (particularly steels with more than 9% Cr). In some cases, even very highly alloyed materials (i.e., 12% Cr, type 316 stainless steel (SS) and type 317 SS), and in severe cases even 6% Mo stainless steel have been found to exhibit sensitivity to corrosion under these conditions.

The corrosion reaction processes involve the formation of iron naphthenates:

$\begin{array}{l}\mathrm{Fe}+\mathrm{2RCOOH}\to \mathrm{Fe}{(\mathrm{RCOO})}_2+{\mathrm{H}}_2\hfill \\ \mathrm{Fe}{(\mathrm{RCOO})}_2+{\mathrm{H}}_2\mathrm{S}\to \mathrm{FeS}+\mathrm{2RCOOH}\hfill \end{array}$ (3.4)

(3.4)

The iron naphthenates are soluble in oil and the surface is relatively film free. 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, the formation of a potentially protective layer of iron sulfide occurs on the unit walls and corrosion is reduced (Kane and Cayard, 2002; Yépez, 2005). When the reduction product is water, coming from the reduction of sulfoxides, the NAC is enhanced (Yépez, 2005).

Thermal decarboxylation can occur during the distillation process (during which the temperature of the crude oil in the distillation column can be as high as 400°C):

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

However, not all acidic species in petroleum are derivatives of carboxylic acids (COOH) and some of the acidic species 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). In addition, for the acid species that are volatile, NAP are most active at their boiling point and the most severe corrosion generally occurs on condensation from the vapor phase back to the liquid phase.

NAC is one of the serious long known problems in the petroleum refining industry (Derungs, 1956; Piehl, 1960; Gutzeit, 1976a, b; Piehl, 1988; Slavcheva et al., 1998, 1999; Qu et al., 2005, 2006). The rates of NAC increase with the temperature rising and are also influenced obviously by TAN, that is, the corrosion rates increase with the TAN increasing. 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 (Wang et al., 2011). In petroleum refining industry, influence factors (such as temperature, TAN, fluid velocity, and material) work simultaneously, so 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.

High temperature naphthenic acid corrosion mainly occurs at temperatures above 200°C (390°F), in particular above 220°C (430°F), affecting equipment that has the closest contact with naphthenic acid. The most seriously affected component is the vacuum distillation column system of the atmospheric and vacuum distillation system, including the vacuum heater, transfer line, vacuum draw three, vacuum draw four, vacuum tower feeding line, and internal structures. High temperature naphthenic acid corrosion includes four main steps: (i) naphthenic acid molecules are transferred to a metal surface, (ii) the molecules become adsorbed onto the metal surface, (iii) the molecules react with surface active centers, and (iv) corroded materials are desorbed.

NAC is heavily influenced by temperature—typically corrosion at low temperatures is not significant but, in the boiling state especially in a high temperature, anhydrous environment corrosion is most significant. Most high temperature naphthenic acid corrosion occurs in the liquid phase, but if naphthenic acid is condensed in the gas phase then gas phase corrosion may occur and the extent of corrosion will be influenced by acid value.

Isolated deep pits in partially passivated areas and/or impingement attack in essentially passivation free areas are typical of NAC. 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. NAC 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 is a function of the TAN, sulfur content, and possibly other unidentified factors. Crude oils that have high TANs and low sulfur are particularly corrosive. It is possible to develop a series of operating envelopes in terms of the TAN and sulfur (i.e., 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 type of 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 the feed TAN is further increased, corrosion will affect the atmospheric transfer line and HAGO circuits and the bottoms of both towers.

Predictive models of considerable complexity exist but the reliability of such models is not always guaranteed—remembering that such models may have been derived using data from the corrosive character of model compound which are not always representative of the constituents of the naphthenic acid fraction. Furthermore, because of the questionability of the models, it is necessary to apply a monitoring program using hot corrosion probes and hot ultrasonic testing and radiographic testing to confirm the predictions of any active model and to adjust the predicted limits as necessary. While this may seem an unnecessary action, it may permit the use of a simple model which is adjusted on the basis of the real data.

While high TAN crude oils primarily affect the high temperature sections of the atmospheric distillation unit and the vacuum distillation unit, they also affect downstream units as well (such as coker preheaters, catalytic cracker preheater, and hydrotreater preheaters). Some crude oils have also caused overhead system corrosion because of their inefficient performance of the desalting operation.