Removing Acid Constituents from Crude Oil
Removing naphthenic acid constituents from crude oils and/or preventing acidic corrosion is regarded as one of the most important processes in heavy oil upgrading. Current industrial practices either depend on dilution or caustic washing methods to reduce the total acid number of heavy crude oils. However, neither of these approaches is entirely satisfactory. For instance, by blending a high acid crude oil with a low acid crude oil it is possible to reduce the naphthenic acid content of the blended feedstock to an acceptable level. However, whether or not this type of action can mitigate naphthenic acid corrosion is still open to debate.
This chapter presents a review of the various methods that are in use to attempt to mitigate naphthenic acid corrosion during crude oil refining. The final word is that such methods may be crude oil dependent and there may be no one method that can be used for all crude oils to reduce the effects of the naphthenic acid constituents.
Keywords
Physical methods; chemical methods; corrosion monitoring; corrosion prevention; the future
5.1 Introduction
Naphthenic acids having the empirical formula CnH2n+zO2, occur naturally in crude oil (see Chapter 1) (Clemente and Fedorak, 2005). However, crude oils containing naphthenic acids are only united by the value of the total acid number (TAN) and will vary extensively in most other chemical properties and physical characteristics (see Chapter 1). While most high acid crude oil may be medium to heavy crudes (in terms of the API gravity), such crude oils usually are low in sulfur content (with the notable exception of Venezuelan grades).
Removing naphthenic acid constituents from crude oils and/or preventing acidic corrosion is regarded as one of the most important processes in heavy oil upgrading (Scattergood and Strong, 1987; White and Ehmke, 1991). Current industrial practices either depend on dilution or caustic washing methods to reduce the TAN of heavy crude oils (Table 5.1). However, neither of these approaches is entirely satisfactory.
Table 5.1
Methods for Mitigating Corrosion due to the Presence of Naphthenic Acids
In addition, process control changes (that are acceptable to the refiner without creating losses in the margin) may provide adequate corrosion control if there is possibility to reduce charge rate and temperature. For long-term reliability, upgrading the construction materials to a higher chrome and/or molybdenum alloy is the best solution. Currently and in the future, modifying or removing naphthenic acids would come from four areas: adsorption, extraction, neutralization (esterification), decarboxylation, and hydrotreating.
However, petroleum research is often frustrated by the wide variability in molecular composition among nominally similar streams. Crude oils vary in composition due to differences in source rock, maturation conditions, and reservoir environments (Speight, 2014a). Process oils are a function of not only the source oil but also process design, catalyst, and operating conditions. Because it is not practical to study every possible compound in a stream, model compounds are used as surrogates for a class of molecules. Typically, tests are run in a benign matrix oil to facilitate analysis of the compound’s behavior. In reality, the research objectives define the type of model compound selected for experiments. Compounds with different functional groups may be used for fundamental physical phenomena or reaction mechanism studies. In process studies, the stream of interest dictates the boiling range and hence a molecular weight range of model compounds to be studied. In sophisticated molecular modeling, molecular structures (isomers) must be considered.
As high acid crude oil and heavy crude oil output rises because of the enhanced exploitation and utilization of oil resources in the world, the acid values of heavy crude oils are also increasing. In recent years, the world’s high acid crude oil production has been increasing by 0.3% per year. The acid crude oil can induce serious corrosion of equipment during oil processing, resulting in its oversupply and relatively low price on the international market. The acid value of crude oil is mainly caused by naphthenic acids, which are the major acid components in crude oil, accounting for about 90% of acidic ingredients, which are the main chemical components causing serious corrosion of oil processing equipment (see Chapters 3 and 4). Besides naphthenic acids, there are fatty acids, aromatic acids, inorganic acids, mercaptans, hydrogen sulfide, and phenols existing in the crude oil. Corrosion caused by naphthenic acids is different from that caused by sulfur, because the latter can induce uniform corrosion while the former can cause localized corrosion or pitting, which is influenced by the acid value, temperature, flow rate, kind of medium, changes in physical state, and other factors, it is not always easy to detect the cause of corrosion.
Deacidification of high acid crude oil is considered in two ways: (i) physical methods, such as blending or more obvious physical methods, which are designed to separate the naphthenates from crude oil without changing their chemical state, such as adsorption and extraction and (ii) chemical methods which are associated with taking advantage of chemical properties of the crude oil for naphthenic acid removal such as the use of inhibitors, decarboxylation, and esterification.
Many concepts have been advanced with the goal of removing naphthenic acids (deacidification) from acid crude oils. In developing these processes, in many cases model compounds have been used to probe physical properties and reaction mechanisms. The characteristic of an ideal model compound is defined by research objective, functional group, boiling range, and structure as revealed by advanced characterization of a process stream. However, availability often limits research to less than ideal compounds. This limitation must be recognized in building or evaluating engineering models.
The presence of naphthenic acids in crude oil during refining operations may cause operational issues, such as foaming during crude oil desalting or other operation units as well as carrying cations through the refining process that may cause catalyst deactivation (Shi et al., 2008).
5.2 Physical Methods
5.2.1 Blending
Blending (sometimes referred to as dilution) may be used to reduce the naphthenic acid content of the feed, thereby reducing corrosion to an acceptable level—the naphthenic acids are not removed but the concentration is reduced through the blending operation. In fact, crude oil blending is the most common solution to high acid crude processing. Blending of higher naphthenic acid content oil with low naphthenic acid content oil can be effective if proper care is taken to control crude oil and distillate acid numbers to proper threshold levels. For example, blending a high acid crude oil with a low acid one may reduce the naphthenic acid content to an acceptable level, but the acidic compounds remain and the value of the low acid oil is diminished. Blending of heavy and light crudes changes shear stress parameters and might also help reduce corrosion. Blending is also used to increase the level of sulfur content in the feed and inhibit to some degree naphthenic acid corrosion.
However, blending two different feedstocks may lead to other issues such as incompatibility of the heavy crude constituents (such as the asphaltene constituents) in the more paraffinic light crude oil (Speight, 2014a). Some oils and refinery streams are inherently incompatible—the main cause being the insolubility of the asphaltene constituents. While there are many models claimed to predict incompatibility, the only true model is based on data from the actual components of the blend under investigation. Rules designed to predict incompatibility are not always adaptable from one system to another and following such rules may not diminish the problems associated with incompatibility.
The common industry practice to overcome the problem of naphthenic acid corrosion consists of blending with sweet crude or washing with caustic solution to lower the acid level, addition of corrosion inhibitor and utilization of expensive corrosion-resistant construction material for the processing unit. Lately, as the production of heavy crude oil continues to increase, these practices have become less satisfactory and other methods of naphthenic acid reduction have been investigated.
Finally, it must be recognized that blending does not deacidify high acid crude oil. The concentration of the naphthenic acids is reduced by blending high acid crude oil to low acid crude oil or no acid crude oil. The naphthenic acids remain in the blended product and those naphthenic acids that have a high propensity to react with a catalyst (resulting in catalyst deactivation or catalyst destruction) will do so.
5.2.2 Adsorption
Clay minerals have and continue to be used in the petroleum industry because they can interact with many organic compounds to form complexes of varying stabilities and properties (Speight and Ozum, 2002; Hsu and Robinson, 2006; Gary et al., 2007; Speight, 2014a). Clay organic interactions are multivariable reactions involving the silicate layers, the inorganic cations, water, and the organic molecules. The chemical affinity between the acid compound and the solid surface depends on structure (molecular weight, chain length, etc.) of the acid molecule, functional groups present in the acid molecule such as hydrophobic groups (
CCCC), electronegative groups (C
O, COC, OH), π bonds (CC, aromatic rings), and configuration of the acid molecule. Adsorption of organic molecules on minerals such as clays has already been considered as a major process in the diagenesis and maturation of organic matter to petroleum. Surface functional groups in clay minerals play a significant role in adsorption processes. Surface functional groups can be organic (e.g., carboxyl, carbonyl, phenolic) or inorganic molecular units. The major inorganic surface functional groups in soils are the siloxane surface associated with the plane of oxygen atoms bound to the silica tetrahedral layer of a phyllosilicate and hydroxyl groups that are associated with the edges of inorganic minerals such as kaolinite, amorphous materials, metal oxides, oxy-hydroxides, and hydroxides.
The presence of the negative surface charge also makes the clay an excellent adsorbent for organic cations. In the present work, it was used as a clay (bentonite) activated with organic acids to increase its surface area. The adsorptive properties of these activated clays depend on the chemical nature of the surface, and the adsorption process is influenced by electrostatic interaction between adsorbate molecules and adsorption sites on clay surface, the nature of the exchangeable ion located in the interlayer, and the range of hydration of the positive ion. Polar molecules or polarizable ones are efficiently adsorbed by these clays. This could favor that acid composites, as naphthenic ones, could be attracted for the negative charge layers of the clay and then removed from oil. These acids can be ionized or bonded in hydrogen bridges inside the oil.
In addition, alumina presents a high surface area for adsorption and its global surface charge is positive, what would favor the adsorption of negatively charged composites, through an electrostatic interaction. This could lead to the assumption that the highest reduction of TANs, obtained with alumina, may result from the adsorption of naphthenic acid totally dissociated. However, as it is a nonaqueous environment, it is not possible to discard the probability that the adsorption process to also occurring through interactions between molecules in the acid form and the weak basic sites present in great amount in alumina. Moreover, it is important to point out that, as this is a real sample, naphthenic acids of differentiated force are possibly present in the oil and can be adsorbed by distinct processes. In addition, other compounds present in the oil can also be adsorbed, contributing to the final TAN.
As these acids are, in general, at low concentrations, an efficient treatment can be the use of adsorption processes. There are few processes reporting the removal of naphthenic acids from petroleum fractions using various adsorbents such as magnesium oxide and aluminum oxide. The adsorption of naphthenic acids has already been reported on zeolites, aluminosilicates from catalyst manufacturing process waste, silica gel, clays, and ion exchange resins. These acids can be recovered using polar solvents (Gaikar and Maiti, 1996; Zou et al., 1997).
Other processes include adsorption using ceramics or clay, or alumina (Pereira Silva et al., 2007; Saad et al., 2014). Adsorption processes using adsorbents such as clay are also in use (Pereira Silva et al., 2007). The adsorption process in clay involves its great surface area and the presence of a negative global charge in its surface, in virtue of the isomorphic replacement of cations in the crystalline net of the mineral. This charge is generally balanced for the adsorption of inorganic cations (e.g., H+, Na+, Ca2+) in the internal and external surfaces of material (Gürses et al., 2006).
As another example, the acidity of high acid crude oil (such as Sudanese crude oil) can be reduced by use of clay, which was activated by concentrated sodium hydroxide (Saad et al., 2014). The TAN of Fula high acid crude was 8.51 mg KOH/g, and the TAN of Nile blend was 1.06 mg KOH/g, which can be reduced to 6.27 and 1.05 mg KOH/g, respectively, by activated clay of 3 M NaOH composed mainly of muscovite as explained by XRD analysis. The adsorption naphthenic acids using local activated clay has proved to be an efficient and effective process, but the disposal of spent clay remains an issue.
5.2.3 Extraction
Solvent extraction leads to the generation of excessive quantities of secondary industrial wastewater. Additionally, water/crude emulsions of difficult separation are generated during the process (Ding et al., 2009). Adsorption using ionic exchange resins or other adsorbent materials such as clays may only be applied when dealing with light crudes and light distillation fractions.
The most used and effective process to remove naphthenic acids from oils is the liquid–liquid extraction, especially when using ammonia or alkali alcoholic solutions. However, these systems usually form stable emulsions (Gaikar and Maiti, 1996). Therefore, there are several proposals for the liquid–liquid extraction using different solvent systems (Danzik, 1987; Sartori et al., 1997; Varadaraj et al., 1998; Gorbaty et al., 2000; Sartori et al., 2001; Greaney, 2003).
An example of extractive removal of naphthenic acids from crude oil products invokes the use of a solvent system comprising liquid alkanols, water, and ammonia in certain critical ratios to facilitate selective extraction and easy separation. However, when applied to whole crudes, there is the possibility of emulsion formation that will prevent separation of the naphthenic acids (Danzik, 1987).
Naphthenic acids have also been removed from high acid crudes by treating the starting crude oil containing naphthenic acids with an amount of an alkoxylated amine and water under conditions and for a time and at a temperature sufficient to form a water-in-oil emulsion of amine salt to produce a crude oil having decreased amounts of organic acids (Varadaraj et al., 2000).
In another example, a simple solvent system is the sodium hydroxide–ethanol system (Shi et al., 2010). In the proposed process, a sodium hydroxide solution of ethanol was used as the acid removal reagent by mixing with the crude oil and then allowing the two phases to separate, with the naphthenic acids being extracted from the crude oil. Data indicated that the optimal content of sodium hydroxide in crude oil was 3000 μg/g and the optimal extraction time was 5 min with the reagent/oil ratio being 0.4:1 (w/w). The suitable reaction temperature could be room temperature. The TAN of the crude oil was lowered from 3.92 to 0.31 mg KOH/g.
Another potential process (Greaney, 2003) involves contacting a crude oil or a petroleum distillate stream in the presence of an effective amount of water, a base selected from Group IA and Group IIA hydroxides and ammonium hydroxide and a phase transfer agent at an effective temperature (i.e., at which the water is liquid to 180°C, 355°F) for a time sufficient to produce a treated petroleum feed having a decreased naphthenic acid content and an aqueous phase containing naphthenate salts, phase transfer agent, and base. This process facilitates the extraction of higher molecular weight naphthenic acids (in addition to lower molecular weight naphthenic acids), which otherwise would remain in the petroleum stream following extraction with caustic alone. This result is a lower TAN content and, in additional, the presence of the phase transfer agent has been found to reduce the emulsion formation that can occur during caustic treatment leading to enhanced processability.
Examples of suitable phase transfer agents include quaternary onium salts, i.e., basic quaternary onium salts (i.e., hydroxides), nonbasic quaternary onium salts such as quaternary onium halides (e.g., chlorides), hydrogen sulfates, crown ethers, open chain polyethers such as polyethylene glycols. The lengths of the hydrocarbyl chains may be varied within the disclosed ranges and the hydrocarbyl groups may be branched or otherwise substituted with noninterfering groups, provided that the accessibility and suitable organophilic nature are maintained. Also, the structure must allow for close approach and strong electrostatic interaction of the onium cation and the hydroxide anion, OH−:
This resulting anionic species is less soluble in the petroleum stream due to its electrostatic charge and preferentially equilibrates to the aqueous stream.
A new class of solvents, namely the ionic liquids, has recently shown promising application for reducing the acid content in crude oil and these are the ionic liquids, which are reactive solvents (Gordon, 2001). Ionic liquids are a relatively new class of solvents and have shown promising application for reducing the acid content in crude oil. Ionic liquids are comprised of entirely free ions within a liquid state that exist over a wide temperature range.
Being composed entirely of ions, ionic liquids possess negligible vapor pressure, and the wide range of possible cations and anions they contain means that other solvent properties may be easily controlled (Kume et al., 2008). For example, an ionic liquid can be used for deacidification of acidic oil, especially for the removal of the naphthenic acids that can be extracted with the conventional technique. The ionic liquid has demonstrated its good performance for acid removal from the oil sample.
Ionic liquids comprise of entirely free ions within a liquid state that exist over a wide temperature range. Besides reducing the acid content of the crude oil, several research works have also demonstrated the ability of some ionic liquids (imidazolium based) to remove sulfur compounds. In another study, the same ionic liquids with different anions such as thiocyanate, octyl sulfate, and trifluoromethane sulfonate were also shown to be able to extract nitrogen and sulfur compounds (Bosmann et al., 2001; Nie et al., 2006; Hansmeier et al., 2011; Kędra-Krolik et al., 2011).
Thus, the use of ionic liquids could be for a multitude of functions for upgrading the crude oil through removal of the undesirable impurities within a single processing step namely liquid–liquid extraction. In addition, features such as higher thermal stability with extremely low vapor pressure compared to the conventional solvents and coupled with the possibility of regeneration have given significant advantages to ionic liquids for replacing conventional solvents.
In addition to the use of ionic liquids in the petroleum industry, there are already considerable published works discussing the capability of ionic liquids in extracting carboxylic acids investigated the potential of imidazolium ionic liquids as extractants for naphthenic acids (Matsumoto et al., 2004; Marták and Schlosser, 2007).
The ionic liquids 1-n-butyl-imidazolium with three different anions namely thiocyanate (SCN), octyl sulfate (OCS), and trifluoromethane sulfonate have been used to show the potential for this method and extract two types of carboxylic acids namely benzoic acid and n-hexanoic acid, from the hydrocarbon liquid. The results show that the ionic liquids exhibit high extraction efficiency for both carboxylic acids used. Using computational molecular simulation software, the interaction mechanism was investigated based on surface polarization charge densities. From the simulation results, the extraction performance of the ionic liquids can be predicted based on capacity and selectivity parameter (Kamarudin et al., 2012a, b).
However, the application of new technologies such as the use of ionic liquids in the refinery has still to be proven. Many issues have to be solved before, for example, ionic liquids may be successfully applied in the petroleum industry. The economical, technological, and environmental feasibility of large-scale production and utilization of ionic liquids must be asserted before any petroleum company accepts their daily use. The effect of the presence of ionic liquids in crude oil during production, transport, and refining must be asserted in order to identify operational issues. Even if ionic liquids have still to prove their safe utilization in daily and routine petroleum operations, there is a window for the use of these solvents in problems of the petroleum refining industry.
5.3 Chemical Methods
Naphthenic acids (excluding the mineral acids such as hydrochloric acid) from oil consist primarily of monocarboxylic acids, including aliphatic, naphthenic, and aromatic acids (see Chapter 1). Naphthenic acids are predominantly found in immature heavy crudes due to the fact that they come from the biodegradation in petroleum hydrocarbon reservoirs (Biryukova et al., 2007). The acidity of crude oil is associated with the acid number and it is expressed in milligrams of potassium hydroxide necessary in order to neutralize one gram of crude. Crude oils with acidity levels above 0.5 mg KOH/g are considered potentially corrosive for refinery units (see Chapter 1) (Alvisi and Lins, 2011). Aside from the corrosive effect, naphthenic acids lead to formation of stable emulsions by forming metallic naphthenates that reduce interfacial tension, affecting the processes that involve phase separation stages (Ding et al., 2009). Additionally, calcium naphthenates precipitate along the preheating train and furnaces, promoting coke formation (Simon et al., 2008).
Naphthenic acid removal is one of the most important aspects in safe processing of opportunity crudes. The study and implementation of naphthenic acid removal processes is of vital importance for the adequate exploitation of many heavy types of crude that exhibit high acidity. Investigations regarding acidity reduction in crudes include nondestructive processes such as solvent extraction and adsorption (Gaikar and Maiti, 1996; Wang et al., 2006; Norshahidatul Akmar et al., 2012).
5.3.1 Neutralization
Naphthenic acids have been formerly identified as carboxylic acids in crude oil (see Chapter 1) and it is reasonable to assume that neutralization (caustic treatment) can be employed to substantially remove naphthenic acid constituents. However, the process generates significant amounts of wastewater and the interfacial properties of the naphthenic acid fraction (see Chapter 1) result in the formation of emulsions that are problematic to treat. In particular, once an emulsion is formed, it is very difficult to remove (Ese et al., 2004).
5.3.2 Use of Inhibitors
Corrosion inhibitors are often the most economical choice for mitigation of naphthenic acid corrosion. Effective inhibition programs can allow refiners to defer or avoid capital intensive alloy upgrades, especially where high acid crudes are not processed on a full-time basis (Duan et al., 2012).
An example of the use of the inhibition of naphthenic acid corrosion includes the use of a polysulfide corrosion inhibitor for inhibiting naphthenic acid corrosion in crude distillation units and furnaces (Petersen et al., 1993). Additionally, a variety of attempts have been made to address the problem of naphthenic acid corrosion by using corrosion inhibitors for the metal surfaces of equipment exposed to the acids, or by neutralizing and removing the acids from the oil. Examples of these technologies include treatment of metal surfaces with corrosion inhibitors such as oil soluble reaction products of an alkyne diol and a polyalkene polyamine (Edmonson, 1987) or by treatment of a liquid hydrocarbon with a dilute aqueous alkaline solution, specifically dilute aqueous NaOH or KOH (Verachtert, 1980). However, issues may arise from the use of aqueous solutions that contain higher concentrations of base because these solutions form emulsions with crude oil, necessitating use of only dilute aqueous base solutions which is the principle behind many alkaline flood recovery operations using alkaline flood (Speight, 2009, 2014a). There is a claim that treatment of heavy oils and petroleum resids having acidic functionalities with a dilute quaternary base such as tetramethylammonium hydroxide in a liquid (alcohol or water) avoids emulsion formation (Liotta, 1981).
Injection of corrosion inhibitors may provide protection for specific fractions that are known to be particularly severe. Monitoring needs to be adequate to assure the effectiveness of the treatment. Process control changes may provide adequate corrosion control if there is the possibility of reducing charge rate and temperature. For long-term reliability, upgrading the construction materials is the best solution. At temperatures above 285°C (550°F), with very low naphthenic acid content, cladding with chromium (Cr) steels (5–12% Cr) is recommended for crudes of >1% sulfur. When hydrogen sulfide is evolved, an alloy containing a minimum of 9% (w/w) chromium is preferred. In contrast to high temperature sulfidic corrosion, low alloy steels containing up to 12% (w/w) Cr do not seem to provide benefits over carbon steel in naphthenic acid service. Type 316 stainless steel (having >2.5% w/w molybdenum, Mo) or Type 317 stainless steel (having >3.5% w/w Mo) is often recommended for cladding of vacuum and atmospheric columns.
While high temperature naphthenic acid corrosion inhibitors have been used with moderate success, potential detrimental effects on downstream catalyst activity must be considered. Inhibitors effectiveness needs to be monitored carefully. For severe conditions, Type 317L stainless steel or other alloys with higher molybdenum content may be required.
5.3.3 Decarboxylation
Thermal decarboxylation and catalytic decarboxylation of naphthenic acids are an alternative for the processing of high acidity crudes (Zhang et al., 2004, 2005, 2006; Ding et al., 2009; Yang et al., 2013). Typically, the weak nature of naphthenic acids can be utilized in the neutralization and esterification reactions for converting them into easily removable salts and deacidification of crude oil can also be achieved by destructive hydrogenation for removal of carboxyl radicals directly (Duan et al., 2012).
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 (750°F)). A metal oxide catalyst, magnesium oxide (MgO), has been developed and its effectiveness in catalyzing decarboxylation reactions involving carboxylic acid compounds such as naphthenic acid has been determined based on the formation of carbon dioxide and the conversion of acid (Zhang et al., 2006). The major reaction takes place in the temperature range of 150–300°C (300–570°F):
The role of magnesium oxide in the system is considered to be multiple. It has the ability to adsorb acidic compounds via acid–base neutralization and it can also promote reactions such as decarboxylation and hydrocarbon cracking at the increased temperature. Direct application of MgO to crude oil results in significant naphthenic acid removal and lower total acidity of the oil as evidenced by a decrease in RCOOH concentration as determined by Fourier transform infrared spectroscopy (FTIR) and a lower TAN.
Catalytic decarboxylation has also been proven as an effective technique in the removal of naphthenic acids in the crude oil samples using Cu/Mg (10:90) Al2O3 and Ni/Mg (10:90) Al2O3 catalysts. The calcination temperature for both catalysts was at 1000°C (1830°F). Both catalysts were highly amorphous (Norshahidatul Akmar et al., 2013).
In another example, Liaohe crude oil with high TAN was subjected to thermal reaction at 300–500°C (570–930°F). Reaction products were collected and analyzed by negative ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR MS) to determine acid compounds in the crude oil. The double bond equivalence (DBE) versus carbon number was used to characterize the oxygenated components in the feed and reaction products. The O2 class which mainly corresponds to naphthenic acids decarboxylated at 350–400°C (660–750°F), resulting in a sharp decrease in the TAN. Phenols (O1 class) are more thermally stable than carboxylic acids. Carboxylic acids were also thermally cracked into smaller molecular size acids, evidenced by the presence of acetic acid, propanoic acid, and butyric acid in the liquid product, which are also responsible for corrosion problems in refineries (see Chapters 1, 3, 4) (Yang et al., 2013).
The end result of the formation of low molecular weight acidic species is treated in the overheads in refineries. A combined approach to front end treating at crude inlet to heaters and preheat exchangers should be considered. It is commonly assumed that acidity in crude oils is related to carboxylic acid species, i.e., components containing a COOH functional group. While it is clear that carboxylic acid functionality is an important feature (60% of the ions have two or more oxygen atoms), a major portion (40%) of the acid types are not carboxylic acids. In fact, naphthenic acids are a mixture of different compounds which may be polycyclic and may have unsaturated bonds, aromatic rings, and hydroxyl groups (Rikka, 2007). Even the carboxylic acids are more diverse than expected, with approximately 85% containing more heteroatoms than the two oxygen atoms needed to account for the carboxylic acid groups. Examining the distribution of component types in the acid fraction reveals that there is a broad distribution of species.
Several metal oxide catalysts have been found to be very effective to the catalytic decarboxylation, which were verified by the formation of carbon dioxide. A newly developed catalyst with an additive was able to reduce the TAN of a heavy crude oil from 4.38 to 0.60 at 300°C (570°F) for 4 h. A newly developed catalyst with an additive was able to reduce the TAN of a heavy crude oil from 4.38 to 0.60 at 300°C (570°F) for 4 h. Flow reaction test shows that one of the catalysts we developed can maintain its effectiveness for 12 h at 250°C (480°F). In addition, several natural occurring clays showed promise as adsorption agents to the selective removal of acids. The adsorption capacity of one of the clays was as high as about 70 mg NA/g clay (Zhang et al., 2004).
All of the catalysts (MgO, Ag2O/Cu2O, HZSM-5 zeolite, and Pt/Al2O3) show excellent catalytic decarboxylation activities at relatively low temperature ca. 200–300°C (390–570°F). The decarboxylation mechanism was investigated through theoretical calculation and product/intermediate analyses. It has been clear that magnesium oxide catalyzes the decarboxylation reaction through a ketone forming mechanism with 2 moles of carboxylic acid, which give rise to the formation of 1 mole of carbon dioxide. Silver oxide (Ag2O) and cuprous oxide (Cu2O) are, most possibly, involved in the decarboxylation process via a free radical mechanism. On the other hand, the high activities of zeolite towards decarboxylation would be caused by carbon–carbon bond cracking catalyzed by the strong acidic sites on zeolite. Due to the complexity of the oil composition and poison issues, not all of these catalysts can be directly applied in crude oil. However, their applicability in organic chemistry as well as other functional group modification would be highly predicable.
However, not all acidic species in petroleum are derivatives of carboxylic acids (COOH) and some of the acidic species are resistant to high temperatures (Speight and Francisco, 1990; Speight, 2014a). 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. In addition, for the acid species that are volatile, naphthenic acids 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.
However, in order to obtain noticeable reduction percentages, it is necessary to operate at temperatures above 250°C (480°F), which could lead to corrosion problems in these units. Esterification is a promising alternative for safe processing of these types of opportunity crudes because it is possible to reach significant acidity reduction percentages at temperatures below 250°C (480°F) even in the absence of a catalyst (Sartori et al., 2001).
The serious problems, such as corrosion and emulsion, might be caused when the crude oil with high naphthenic acid content was processed in refinery. A method was developed by the catalytic esterification process to reduce the acidity of crude oil with high naphthenic acid content. The experimental results demonstrated that ZnMgAl-HTlc was an effective catalyst for the esterification, and structure of ZnMgAl-HTlc had not been changed during the esterification process (Huang et al., 2009). Therefore, this acid removal technique could assist refineries to process the high acid crude oil without upgrading the materials of equipment and pipelines.
Catalytic decarboxylation is a well-established chemical reaction in organic and biochemical processes that has been widely applied in organic synthesis and even applied to the identification of coal structure through oxidative decarboxylation (Ozvatan and Yurum, 2002). Cu-based catalysts, predominately employed homogeneously, are commonly used and, in some cases, the presence of organic nitrogen compounds is also necessary (Darensbourg et al., 1994). Additionally, there are reports that zirconium oxide (ZrO2) can promote the catalytic decarboxylation of acetic acid in supercritical water. Tungsten complexes facilitate catalytic decarboxylation of cyanoacetic acid through homogeneous catalysis. Zeolite has also been applied in the catalytic decarboxylation of benzoic acid but the reaction occurred at temperatures on the order of 400°C (750°F). Nevertheless, most of these studies are limited to the delicate catalyst system such as transition metal complexes, which have relatively low stabilities at the increased temperatures (Zhang et al., 2004; 2005).
5.3.4 Esterification
Studies concerning acid reduction through esterification have been performed with light distillation currents and obtained satisfactory results using a catalyst such as tin oxide and aluminum oxide (SnO-Al2O3) (Wang et al., 2007) which can bring about a significant reduction in acidity—1.7 to <0.1 mg KOH/g as measured by the standard test methods for acids in crude oil (see Chapter 1)—using a fixed bed reactor, a methanol/crude ratio of 0.010, and an optimum reaction temperature of 280°C (535°F). Another kinetic study (Wang et al., 2008) of the esterification reaction of naphthenic acids in a diesel fuel used a SnO catalyst upon the reaction’s kinetic parameters and showed that the kinetic reactions for esterification must be determined for each type of crude.
5.4 Corrosion Monitoring and Prevention
Combating or preventing corrosion is typically achieved by a complex system of monitoring, preventative repairs, and careful use of materials (Garverick, 1994; Speight, 2014b). In fact, corrosion monitoring is just as important as recognizing the problem and applying controls. Monitoring attempts to assess the useful life of equipment when corrosion conditions change and how effective the controls are. Techniques used for monitoring depend on what the equipment is, what it is used for, and where it is located.
5.4.1 Monitoring and Measurement
Corrosion monitoring techniques can help by: (i) providing an early warning that damaging process conditions exist which may result in a corrosion-induced failure, (ii) studying the correlation of changes in process parameters and their effect on system corrosivity, (iii) diagnosing a particular corrosion problem, identifying its cause and the rate controlling parameters, such as pressure, temperature, pH, and flow rate, (iv) evaluating the effectiveness of a corrosion control/prevention technique such as chemical inhibition and the determination of optimal applications, and (v) providing management information relating to the maintenance requirements and ongoing condition of plant (Speight, 2014b).
Typically, a corrosion measurement, inspection and maintenance program used in any industrial facility will incorporate the measurement elements provided by the four combinations of online/offline, direct/indirect measurements: (i) corrosion monitoring direct, online, (ii) nondestructive testing direct, offline, (iii) analytical chemistry indirect, offline, and (iv) operational data indirect, online. In a well-controlled and coordinated program, data from each source will be used to draw meaningful conclusions about the operational corrosion rates with the process system and how these are most effectively minimized.
Furthermore, analytical testing of process streams is vital to processing high acid crude oils. The monitoring of TANs and other relevant properties is of high importance (Sastri, 1998; Knag, 2005). Tests involving potentiometric titration are normally used for measurement of the TAN. Elements, such as trace metals, should be monitored with inductively coupled plasma (ICP) mass spectrometry or ICP optical emission spectrometry instruments. These machines use ICP for elemental analysis.
Periodic inspections do not, however, deliver continuous pipework condition data that can be correlated with either corrosion drivers or inhibitors to understand the impact of process decisions and the inhibitor usage on plant integrity. Manual acquisition of ultrasonic wall thickness data is also frequently associated with repeatability limitations and data logging errors.
Permanently installed sensor systems, on the other hand, deliver continuous reliable data. The ultrasonic sensors can be installed on pipes and vessels operating at up to 600°C (1110°F)—such sensors have also been certified as safe for use in most hazardous environments. Continuous monitoring through use of appropriate test method data—such as the iron powder test method (Hau et al., 2003) which is used for detecting anomalous cases where oil samples having high acid numbers exhibit less corrosivity than others having much lower acid numbers or where they show completely different corrosivity despite having similar or the same acid number—can validate that when corrosion is occurring it may be an intermittent process rather than a continuous event. In such cases, it is particularly valuable to be able to correlate the data over time with process and/or inhibitor parameters, including fluid dynamics (Cross, 2013).
The field of corrosion measurement, control, and prevention covers a very broad spectrum of technical activities (Speight, 2014b). Corrosion measurement is the quantitative method by which the effectiveness of corrosion control and prevention techniques can be evaluated and provides the feedback to enable corrosion control and prevention methods to be optimized and a wide variety of corrosion measurement techniques exists (Table 5.2).
Table 5.2
Method of Corrosion Measurement
Nondestructive Testing Analytical Chemistry |
Analytical Chemistry |
Operational Data |
Fluid Electrochemistry |
Corrosion Monitoring |
Some corrosion measurement techniques can be used online, constantly exposed to the process stream, while others provide offline measurement, such as that determined in a laboratory analysis. Some techniques give a direct measure of metal loss or corrosion rate, while others are used to infer that a corrosive environment may exist.
5.4.2 Corrosion Prevention
Corrosion control is an ongoing, dynamic process and in the prevention of metal deterioration by three general ways: (i) change the environment, (ii) change the material, or (iii) place a barrier between the material and its environment. The material does not have to be metal—but is in most cases—and the metal does not have to be steel, but, because of the strength and readily availability and cheapness of this material, usually is a metal. Again, the environment is, in most cases, the atmosphere, water, or the earth is an important contributor to corrosion chemistry.
Many of the methods for preventing or reducing corrosion exist, most of them orientated in one way or another toward slowing rates of corrosion and reducing metal deterioration (Bradford, 1993; Jones, 1996). Corrosion control is the prevention of deterioration by mitigating the chemical reactions that cause corrosion in three general ways: (i) change the environment, (ii) change the material, or (iii) place a barrier between the material and its environment. All methods of corrosion control are variations of these general procedures, and many combine more than one of them. The material does not have to be metal but is a metal or an alloy of metals in most cases. The metal does not have to be steel, but, because of the strength and cheapness of this material, it usually is steel or an alloy of steel. Again, the environment is, in most cases, the atmosphere, water, or the earth, i.e., the constituents of the soil. There are, however, enough exceptions to make corrosion control more complex.
The corrosivity of naphthenic crude oils, its mitigation with chemical inhibitors, and the implementation and continual review of a detailed risk assessment focusing on predicting, monitoring, and mitigating corrosion related effects are essential aspects of processing these crudes (Speight, 2014b).
The critical factors of corrosion by high acid crude oil (or for that matter, any acidic crude oil) must be controlled (Petkova et al., 2009). The corrosion effect of the naphthenic acids can be diminished by blending petroleum of high neutralization number with one of lower neutralization number to obtain raw material with acceptably low acidity. The choice of suitable construction material means the use of corrosion-resistant steel like austenite stainless steel grades—chromium–nickel–molybdenum alloyed ones which have excellent resistance to raw materials containing hydrogen sulfide, chlorides, organic and inorganic acids under high temperature. The introduction of automated corrosion monitoring would also allow the optimization of the amount of inhibitors introduced to change the medium characteristics or technological parameters.
The methods of corrosion control in the presence of naphthenic acids are simply determination of metal loss using corrosion coupons, ultrasonic or hydrogen infiltration measurement of the thicknesses of equipment walls. When supplying petroleum with high content of naphthenic acids, it is necessary to take all precautionary measures before accepting the crude oil for refining. The processing method should be carefully selected to avoid hazardous situations and rapid deterioration of the technological equipment at certain points of the installation for atmospheric distillation of petroleum.
For practical purposes, corrosion in refineries can be classified into low temperature corrosion and high temperature corrosion. Low temperature corrosion is considered to occur below approximately 260°C (500°F) in the presence of water. Carbon steel can be used to handle most hydrocarbon streams in this temperature range, except where aqueous corrosion by inorganic contamination, such as hydrogen chloride or hydrogen sulfide, necessitates selective application of more resistant alloys. High temperature corrosion is considered to take place above approximately 260°C (500°F). The presence of water is not necessary, because corrosion occurs by the direct reaction between metal and environment.
The major cause of low temperature (and, for that matter, high temperature) refinery corrosion is the presence of contaminants in crude oil as it is produced. Although some contaminants are removed during preliminary treating at the wellhead fields as well as during dewatering and desalting it still appears in refinery tankage, along with contaminants picked up in pipelines or marine tankers. However, in most cases, the actual corrosives are formed during initial refinery operations. For example, potentially corrosive hydrogen chloride evolves in crude preheat furnaces from relatively benign calcium chloride (CaCl2) and magnesium chloride (MgCl2) entrained in crude oil (Samuelson, 1954). Mitigation of the problems related to low temperature corrosion is associated with adequate cleaning of the crude oil and removal of corrosive contaminates at the time of, or immediately after, formation.
The pH stabilization technique can be used for corrosion control in wet gas pipelines when no or very little formation water is transported in the pipeline. This technique is based on precipitation of protective corrosion product films on the steel surface by adding pH-stabilizing agents to increase the pH of the water phase in the pipeline. This technique is very well suited for use in pipelines where glycol is used as hydrate preventer, as the pH stabilizer will be regenerated together with the glycol—thus, there is very little need for replenishment of the pH stabilizer.
Some of the ways adapted today to overcome the effects of corrosion are, for example, use of specific types of metal to be longstanding in spite of the effects of corrosion. Carbon steel is used for the majority of refinery equipment requirements as it is cost efficient and withstands most forms of corrosion due to hydrocarbon impurities below a temperature of 205°C (400°F) but as it is not able to resist other chemicals and environments, it is not used universally. Other kinds of metals used are low alloys of steel containing chromium and molybdenum, and stainless steel containing high concentrations of chromium for excessively corrosive environments. More durable metals such as nickel, titanium, and copper alloys are used for the most corrosive areas of the plant which are mostly exposed to the highest of temperatures and the most corrosive of chemicals (Burlov et al., 2013).
Many problems of correct use of corrosion control measures (e.g., injection of chemicals such as inhibitors, neutralizers, biocides, and others) may be solved by means of corrosion monitoring methods (Groysman, 1995, 1996, 1997). For example, hydrocarbons containing water vapors, hydrogen chloride, and hydrogen sulfide leave the atmospheric distillation column at 130°C (265°F). This mixture becomes very corrosive when cooled below the dew point temperature of 100°C (212°F). In order to prevent high acidic corrosion in the air cooler and condensers, neutralizers and corrosion inhibitor are injected in the overhead of the distillation column. In addition, corrosion monitoring equipment should be installed in several places (Speight, 2014b). The more points in the unit used for corrosion monitoring, the better and more efficient is the corrosion coverage.
In summary, control of corrosion requires: (i) evaluation of the potential corrosion risks, (ii) consideration of control options—principally inhibition as well as materials selection, (iii) monitoring whole life cycle suitability, (iv) life cycle costing (LPC) to demonstrate economic choice, and (v) diligent quality assurance (QA) at all stages.
5.4.2.1 Crude Oil Quality
In terms of processing high acid crude oils and mitigating corrosion, crude oil quality is an important aspect of corrosion that is often not recognized as much as other causes (see Chapter 1). Crude oil value—to a refinery—is based on the expected yield and value of the products value, less the operating costs expected to be incurred to achieve the desired yield. Ensuring that the quality of crude oil received is equivalent to the purchased quality (value acquired is equal to value expected) is—with the growing popularity of heavy feedstocks, opportunity crudes, and high acid crudes—one of the greatest challenges facing the refining industry (Cross, 2013; Vetters and Clarida, 2013).
Furthermore, difficulties in minimizing differences between purchased quality and refinery receipt quality are significantly higher when multiple crude oils are processed as a blend, and the complexity of the crude delivery system increases. Shipping crude oil through multiple pipelines and redistribution storage tanks—a reality faced by most inland refiners—results in the delivered crude oil being a composite of the many crude oils. Thus, the resultant composite blend may vary significantly from the expected purchased quality, and the sources of quality problems are much more difficult to estimate.
Issues regarding crude oil properties occur regardless of whether the dominant crude slate is comprised of domestic crude delivered by pipeline or foreign crude delivered via waterborne transportation. In both cases, using simple categories such as gravity or sulfur do not provide an accurate measure of the value of a particular crude oil value, and monitoring only gravity and sulfur does not provide adequate safeguards for the integrity of the crude oil while it is in transit. More sophisticated analyses (with an analysis for constituents likely to cause corrosion and correlated to refinery performance) can provide a comprehensive estimate of quality value to a specific refinery. This analysis needs to give weight to quality consistency, where appropriate, as well as to improved yield, reduced operating expenses, and the compatibility of the crude oil feedstock to the refinery processing hardware.
In addition, a combination of aging plants, greater fluid corrosiveness, and tightening of health, safety, security, and environment requirements has made corrosion management a key consideration for refinery operators. The prevention of corrosion erosion through live monitoring provides a real-time picture of how the refinery is coping with the high demands placed upon it by corrosive fluids. This information can assist in risk management assessments.
5.4.2.2 Acidic Corrosion
Refinery equipment reliability during the processing of high acid crude oils is paramount. Hardware changes—such as upgrading materials construction from carbon steel (CS) and alloy steel to stainless steel (SS) 316/317, which contains molybdenum and is significantly resistant to naphthenic acid corrosion—are complicated tasks and require large capital investment as well as a long turnaround for execution. Alternatives to hardware changes are corrosion mitigation with additives and corrosion monitoring with the application of inspection technologies and analytical tests.
During naphthenic acid crude processing, corrosion at high temperature is mitigated by injecting either phosphate-based ester additives or sulfur-based additives, which provide an adherent layer that does not corrode or erode due to the effect of naphthenic acids. It has been suggested and partially proven that corrosion during processing of high acid crude oils is a lower risk if the sulfur content is high—the relationship between the acid number and amount of sulfur is not fully understood but it does appear that the presence of sulfur-containing constituents has an inhibitive effect (Piehl, 1960; Mottram and Hathaway, 1971; Slavcheva et al., 1998, 1999).
Mitigation of process corrosion includes blending, inhibition, materials upgrading, and process control. Blending may be used to reduce the naphthenic acid content of the feed, thereby reducing corrosion to an acceptable level. Blending of heavy and light crudes can change shear stress parameters and might also help reduce corrosion. Blending is also used to decrease the level of sulfur content in the feed and inhibits, to some degree, naphthenic acid corrosion (see Chapter 1).
5.4.2.3 Sulfidic Corrosion
The presence of sulfur in crude oil can also enhance the corrosive effects of naphthenic acids in the same crude oil (see Chapter 2). 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.
However, sulfidic corrosion 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 pseudopassivity 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).
Any of the 18Cr–8Ni, stainless steel grades can be used to control sulfidation. However, it is best to use the stabilized grades mentioned earlier. Some sensitization is unavoidable if exposure in the sensitizing temperature range is continuous or long term. Stainless equipment subjected to such exposure and to sulfidation corrosion should be treated with a 2% (w/w) soda ash solution or an ammonia solution immediately upon shutdown to avoid the formation of polythionic acid which can cause severe intergranular corrosion and stress cracking.
Vessels for high-pressure hydrotreating and other heavy crude fraction upgrading processes (e.g., hydrocracking) are usually constructed of one of the Cr–Mo alloys. To control sulfidation, they are internally clad with one of the 300 series stainless steels by roll or explosion bonding or by weld overlay. In contrast, piping, exchangers, and valves exposed to high temperature hydrogen–hydrogen sulfide environments are usually constructed of solid 300 series stainless alloys. In some designs, Alloy 800H has been used for piping and headers. In others, centrifugally cast HF-modified piping has been used. High nickel alloys are rarely used in refinery or petrochemical plants in hydrogen–hydrogen sulfide environments because of their susceptibility to the formation of deleterious nickel sulfide. They are particularly susceptible to this problem in reducing environments. As a general rule, it is recognized that the higher the nickel in the alloy the more susceptible the material to corrosion.
Vapor diffusion aluminum coatings (alonizing) have been used with carbon, Cr–Mo, and stainless steels to help control sulfidation and reduce scaling. For the most part, this has been restricted to smaller components. Aluminum metal spray coatings have also been used but not widely nor very successfully.
5.5 The Future
Model compounds have been used to screen functional groups, such as naphthenic acids, for effect on corrosion. Given the complexity of the naphthenic acid fraction (see Chapter 1) caution is advised when applying data from model compound studies to the real world of naphthenic acid corrosion. Nevertheless, there are specific conclusions that can be drawn from the work performed that offer some understanding of the chemical and physical effects that play an active role in naphthenic acid corrosion.
In summary, current solutions for mitigating (reducing) naphthenic acid corrosion include (i) blending feedstock to reduce the TAN of the blending material to <1 mg KOH/g, (ii) continuous injection of corrosion inhibitors, and (iii) upgrading material of construction to a higher chrome and/or molybdenum in severely corroded areas of plant. While acid corrosion will still occur, the rate of corrosion will (hopefully) be markedly reduced.
More permanent methods for mitigating naphthenic acid corrosion include destruction of the naphthenic acids by use of: (i) decarboxylation, in which the carboxyl group reacted to produce carbon dioxide—the DOE/California Institute of Technology process employs a catalyst—CaO (2–5 wt% of oil)—at 300°C (570°F) for 4 h which gives a 70% conversion of the naphthenic acids although deactivation of the catalyst due to impurities was a concern, (ii) the Statoil NAR process, which removes naphthenic acid constituents under mild catalytic hydrotreating conditions, (iii) the Exxon process (1998 US Patent) in which 57–88% of the naphthenic acids are destroyed by heating to 400°C (750°F) for 1 h; however, the use of a sweep gas is critical because water in the feed and reaction water needed to be removed, (iv) the Unipure process (1999 US Patent) in which the acid containing feedstock is mixed with lime (CaO), heated to 260°C (500°F), and separated from reacted lime.
Other (nondestructive) methods include (i) the UOP adsorption process UOP (1995 US patent) in which the acids are adsorbed on nickel oxide, (ii) the Exxon process (2001 US patent) in which the naphthenic acids are adsorbed on a strong base ion exchange resin. Patent was only for lube oils and naphthenic acid removal was approximately 50% (w/w), and (iii) the BP extraction process (WO 2000 patent) in which extraction with polar such as methanol (methanol/crude ratio=1.0) using five extraction stages can lower the TAN from 2.77 to <1.0 mg KOH/g. It is worthy of note at this point that extraction using a simple caustic wash does not suffice as most naphthenic acid constituents (because of their highly hydrocarbon nature—see Chapter 1) have high solubility in the crude oil.
Since high acid crudes are often priced lower than comparable crudes, processing them can have a huge positive impact on the refinery profitability. In our refinery processing, these high acid crudes have resulted in an increased yield of higher value products but some of the realizable value had been offset by the hidden costs and operational difficulty associated with corrosion control programs. These costs negatively impacted the perceived or calculated incremental profit potential, but utilizing new sulfur-based corrosion inhibitor has allowed the refinery to capture the profit gain of higher product yields and controlled corrosion without the operational problems caused by caustic, phosphate ester, and the combined sulfur phosphate ester programs.
Processing high acid crudes which are part of the opportunity crude slate of feedstocks requires higher capital and operating costs than dealing with conventional crude oils. In addition to expanding hydrogen and sulfur plant capacities, processing heavy oil and high acid crudes incurs extra costs because of potential fouling and corrosion problems that lead to poor energy efficiency and increased maintenance requirements. In fact, fouling issues are likely to worsen as refineries process greater volumes of heavier high acid crude. Asphaltene constituents, which make up the highest molecular weight and most polar and aromatic fraction of crude oil, have been blamed for a range of processing problems, including extensive fouling and poor desalter performance (Speight, 2014a,b). Also, high acid crudes are projected to make up approximately 15% of the total crude volume processed worldwide in 2015.
There is also room for the development of alternate methods of naphthenic acid removal from feedstocks. One such method is the use of microwave technology (Huang et al., 2006) and undoubtedly other alternate methods will follow.
The share of high acid crudes in terms of overall crude processed is expected to remain high in the future. These crudes have the potential of offering refiners huge economic benefits due to crude price discounts. However, realizing these benefits requires overcoming the negative impacts of high acidity on product yields and quality, and on the reliability and operations of the refinery.
The rising demand for low sulfur crudes with high gas oil yields will lead to increased imports from acidic crude producers across the globe. The continued need for large volumes of middle distillate will make high acid crudes a common refinery feedstock and since acidic crude worldwide is generally low in sulfur and produced high yields of these products, high acid crudes will be acceptable to many refiners. Unlike other sweet crude oils, high acid crudes will continue to be heavily discounted due to their acidity. Yet acidic crudes will increasingly represent for refiners an ongoing bargain—a group of opportunity crudes, costing less on average, than other available conventional low sulfur crude oils. For example, production of high acid crudes has risen sharply in Asia Pacific, mainly in China, and the parallel growth of the output of high acid crudes in Sudan, West Africa, and Brazil has led many producers to consider accepting such crudes over the long term because of the obvious price differential and the ability to increase product margins.
However, processing high acid crude oil can be risky due to its extreme corrosiveness to processing equipment, which can cause extensive damage, decrease production, and even trigger unexpected refinery outages. In addition, high acid crudes are known to produce diesel with a low cetane number.
In order for refiners to decide whether or not to process high acid crudes, various factors must be considered, with particular consideration given to evolving market conditions and climate change legislation. Since each refinery has its unique set of internal and external challenges and prospects, risk analyses (including strength, weakness, opportunity, and threat) are to be undertaken so that the refiner can maximize profitability (i) by procuring the lower cost crudes, (ii) by making the products in demand both now and in the future, and (iii) by driving down operating costs over the long term.
Naphthenic acid concentration may be a serious source of corrosion for one process and have relatively benign effects for another. However, risk-based assessment of the refinery facilities clearly defines areas for concern if blends of crudes containing naphthenic crudes were to be processed. Analysis will identify all areas exposed to risk of corrosion and requirements to be considered and analyzed prior to processing naphthenic crudes.
In fact, risk-based assessment of the refinery facilities clearly defines areas for concern if blends of crudes containing naphthenic crudes were to be processed (Johnson et al., 2003). Analysis will identify all areas exposed to risk of corrosion and requirements to be considered and analyzed prior to processing naphthenic crudes. High temperature fast flow loop studies can be used more accurately to define the corrosion potential of susceptible areas. Analysis using the fast flow loop provides information on the order and magnitude of corrosive attack by naphthenic species, in the absence of corrosion inhibitors, under conditions anticipated in refinery equipment. It can also be used to conduct metallurgy studies and the effectiveness of corrosion inhibitors applied to the system.
Above all, the uniqueness in process conditions, materials of construction, and blend processed in each refinery and especially the frequent variation in crude or blend processed does still not allow an accurate correlation of plant experience to chemical analysis and laboratory corrosion tests. In addition to corrosion data, there is a need for better monitoring and recording of the process conditions (temperature, velocity, and vaporization) and the analytical data (TAN of cuts, type of acid and sulfur compounds present).