Naphthenic Acids in Petroleum
Crude oil is a highly complex mixture and typically contains thousands of components. Within the large number of constituents of crude oil is a subclass of the oxygen-containing species known as naphthenic acids and the term naphthenic acids is commonly used to describe an isomeric mixture of carboxylic acids (predominantly monocarboxylic acids) containing one or more saturated alicyclic rings.
Naphthenic acids are a naturally occurring, complex mixture of cycloaliphatic carboxylic acids recovered from petroleum and from petroleum distillates and the term naphthenic acid—as used in the petroleum industry—refers collectively to all of the carboxylic acids present in crude oil. Naphthenic acids are classified as monobasic carboxylic acids of the general formula RCOOH, in which R represents the naphthene moiety consisting of cyclopentane and cyclohexane derivatives as well as any acyclic aliphatic acids. Although alicyclic (naphthenic) acids appear to be the more prevalent on the naphthenic acid class, it is now well known that phenol derivatives are also present in crude oil, which includes lower molecular weight organic acids and phenols that are often included in the naphthenic acid category.
This chapter focuses on the occurrence, measurement of the total acid number (TAN), properties, and behavior of naphthenic acids in order to serve as a basis for understanding naphthenic acid-based corrosion in refinery equipment. The chapter also presents a discussion of the possible links between the corrosiveness of the acids through the TAN, molecular size, and structural characteristics.
Keywords
Origin; occurrence; high acid crude; total acid number; TAN; test methods; properties; corrosivity; environmental effects
1.1 Introduction
Crude oil (and the interchangeable term petroleum) is a highly complex mixture and typically contains thousands of components (Speight and Ozum, 2002; Hsu and Robinson, 2006; Gary et al., 2007; Cai and Tian, 2011; Speight, 2014a).
Within the large number of constituents of crude oil is a subclass of the oxygen-containing species known as naphthenic acids and the term naphthenic acids is commonly used to describe an isomeric mixture of carboxylic acids (predominantly monocarboxylic acids) containing one or several saturated fused alicyclic rings (Hell and Medinger, 1874; Lochte, 1952; Ney et al., 1943; Tomczyk, et al., 2001; Rodgers et al., 2002; Barrow et al., 2003; Clemente et al., 2003a, b; Zhao et al., 2012). However, in petroleum terminology it has become customary to use this term to describe the whole range of organic acids found in crude oils; species such as phenols and other acidic species are often included in the naphthenic acid category.
Naphthenic acids are a naturally occurring, complex mixture of cycloaliphatic carboxylic acids recovered from petroleum and from petroleum distillates and the term naphthenic acid—as used in the petroleum industry—refers collectively to all of the carboxylic acids present in crude oil. Naphthenic acids are classified as monobasic carboxylic acids of the general formula RCOOH, in which R represents the naphthene moiety consisting of cyclopentane and cyclohexane derivatives as well as any acyclic aliphatic acids (Brient et al, 1995; Petkova et al., 2009). Although alicyclic (naphthenic) acids appear to be the more prevalent on the naphthenic acid class, it is now well known that phenol derivatives are also present in crude oil (Speight, 2014).
It has generally been concluded that the carboxylic acids in petroleum with fewer than eight carbon atoms per molecule are almost entirely aliphatic in nature; monocyclic acids begin at C6 and predominate above C14. This indicates that the complex structures of the carboxylic acids, which continue to offer challenges in determining these structures, are believed (with reasonable justification) to correspond with those of the hydrocarbons with which they are associated in the crude oil (Robbins, 1998; Rodgers et al., 2002). In the range in which paraffins are the prevailing type of hydrocarbon, the aliphatic acids may be expected to predominate. Similarly, in the ranges in which monocycloparaffins and dicycloparaffins prevail, it has been theorized that the prevalent species will be monocyclic and dicyclic acids, respectively.
More important in the present context, acidic species (naphthenic acids) in the crude oil become active corrosive agents in the distillation column and cause liquid phase corrosion at process temperatures of 250–400°C (480–750°F). Naphthenic acids can cause corrosion in refinery equipment, resulting in costs that are ultimately passed on to the consumer, and the corrosiveness of the acids is believed to be linked to their size and structure. The naphthenic acids content in crude oils is expressed as the total acid number (TAN), which is measured in units of milligrams of potassium hydroxide required to neutralize a gram of oil.
Acidic crude oils are grades of crude oil that contain substantial amounts of naphthenic acids or other acids. They are also called high acid crudes after the most common measure of acidity: the TAN. Arbitrarily, a crude oil with a TAN on the order of 0.5 mg KOH/g acid and higher usually qualifies as high acid crude. At an acid number of 1.0 mg KOH/g crude oil, crude oils begin to be heavily discounted in value. Other than acidity, there appear to be no other distinguishing properties that characterize these oils, although most high acid crude oils often have a gravity that is <29°API and are often (but not always) low in sulfur (except for Venezuelan high acid crudes) and frequently produce high yields of gas oil. Acidic oils can vary widely in most other properties.
The interest in (or willingness to accept) high acid crudes as refinery feedstocks high acid crudes is the result of these oils trading at discounts of several dollars per barrel when compared to conventional (low acid) crude oils but processing high acid crude oils (HACs) is also challenging for refineries, especially those not designed to handle crude oil containing naphthenic acids (Heller et al., 1963; Speight, 2014).
In terms of classification, which is not scientifically based, high acid crudes often fall into the subgroup of crude oils known as opportunity crudes. Generally, opportunity crude oils are often dirty and need cleaning before refining by removal of undesirable constituents, such as high sulfur, high nitrogen, and high aromatics (such as polynuclear aromatic) components. A controlled visbreaking treatment would clean up such crude oils by removing these undesirable constituents (which, if not removed, would cause problems further down the refinery sequence) as coke or sediment.
It is perhaps more correct to separate the HACs as a subclass of crude oil. HACs, which contain significant amounts of naphthenic acids, cause corrosion in the refinery—corrosion is predominant at temperatures in excess of 180°C (355°F) (Ghoshal and Sainik, 2013; Speight, 2014)—and occur particularly in the atmospheric distillation unit (the first point of entry of the HAC) and also in the vacuum distillation units. In addition, overhead corrosion is caused by the mineral salts, magnesium, calcium, and sodium chloride which are hydrolyzed to produce volatile hydrochloric acid, causing a highly corrosive condition in the overhead exchangers and must be removed (Erfan, 2011). Therefore, these salts present a significant contamination in opportunity crude oils. Other contaminants in opportunity crude oils which are shown to accelerate the hydrolysis reactions are inorganic clays and organic acids.
1.2 Origin and Occurrence
Over the next decade (from the time of writing), it is forecast that the supply of high acid crudes (crudes having a TAN in excess of 1.0 mg KOH/g crude oil) will continue to increase significantly, with production rising across the world. All of these crude oils have significant acid numbers. Therefore, corrosion management is of vital importance to ensure that corrosion risk to the plant is minimized and an efficient inspection system must be in place to identify the corrosion which might occur and areas of the plant that might be subject to severe corrosion are identified so that the need for more corrosion resistant alloys can be predicted. In order to understand corrosion and corrosion management, it is necessary to understand the formation (origin) at the time of petroleum generation as well as the nature of naphthenic acids.
The generation of petroleum is associated with the deposition of organic detritus. The detritus deposition occurs during the development of fine-grained sedimentary rocks that occur in marine, near-marine, or even nonmarine. Petroleum is believed to be the product arising from the decay of plant and animal debris that was incorporated into sediments at the time of deposition. However, the details of this transformation and the mechanism by which petroleum is expelled from the source sediment and accumulates in the reservoir rock are still uncertain but progress has been made in environments (Speight, 2014a and references cited therein).
Nevertheless, the composition of petroleum is greatly influenced not only by the nature of the precursors that eventually form petroleum but also by the relative amounts of these precursors (that are dependent upon the local flora and fauna) that occur in the source material. Hence, it is not surprising that petroleum composition can vary with the location and age of the field in addition to any variations that occur with the depth of the individual well. Two adjacent wells are more than likely to produce petroleum with very different characteristics. The same rationale can apply to the occurrence and character of the various constituents of petroleum, not the least of which (in the current context) is the fraction known as naphthenic acids.
Naphthenic acid is the generic name used for all of the organic acids present in crude oils—most of the acids arise as biochemical markers of crude oil origin and maturation (Fan, 1991; Speight, 2014). Most of these acids are believed to have the chemical formula R(CH2)nCOOH, where R is a cyclopentane or cyclohexane ring and n is typically greater than 12 which can lead to the representation of structural characteristics (Tables 1.1–1.3) (Fan, 1991; Hsu et al., 2000; Barrow et al., 2003; Marshall and Rodgers, 2008; Petkova et al., 2009). In addition to R(CH2)nCOOH, a multitude of other acidic organic constituents are also present in crude oil(s) but not all of the species have been fully analyzed and identified. Although saturated carboxylic acids are the predominant compounds found in most crude oils, aromatic and even heterocyclic compounds have also been reported. For example, monoaromatics and diaromatics have also been identified within the naphthenic acid group (Derungs, 1956; Hsu at el., 2000).
Table 1.1
Representative Structures of Naphthenic Acids Found in Crude Oils (Fan, 1991; Hsu et al., 2000; Barrow et al., 2003; Marshall and Rodgers, 2008)
In each case, R is an alkyl group of varying size and there may be more than one alkyl group per molecule.
Table 1.3
Alternate Structural Types of Naphthenic Acids Where the Carboxylic Acid Function Is Attached to an Alkyl Side Chain (US EPA, 2012)
Naphthenic acids are generally described by the formula CnH2n+ZO2, where n is the number of carbons and Z is the hydrogen deficiency index. Z is either zero (for simple fatty acids with one carbon–oxygen double bond) or a negative even integer (acids with additional rings/double bonds) that specify homologous series. On a molecular basis, Z is frequently referred to as the molecular hydrogen deficiency (Hughey et al., 2002; Qian et al., 2001; Hughey et al., 2007).
Finally, naphthenates are the salts of naphthenic acids which have the formula M(naphthenate)2 (M=divalent metal) or are basic oxides with the formula M3O(naphthenate)6. Naphthenate salts form when naturally occurring naphthenic acids in the crude oil come in contact with metal ions (such as calcium) in the produced water under the right conditions of pH and temperature. Naphthenates (RCOO–) are formed during crude oil production due to pressure decrease and release of carbon dioxide, which leads to increase in pH and dissociation of naphthenic acid (RCOOH). Naphthenates can precipitate with metal cations present in brine and form deposits, mainly of calcium naphthenates, which can accumulate in topside facilities, desalters, and pipelines, leading to shutdowns and other serious problems during crude refining.
The metal naphthenates are highly soluble in organic media and, with the naphthenic acids themselves, contribute to the interfacial properties of many crude oils and crude oil products (Varadaraj and Brons, 2007; Pillon, 2008).
In addition, under certain conditions, the naphthenic acids present in acidic crude oil will precipitate with calcium ions (Ca2+ ions) that are present in produced water and form calcium naphthenate and, to a lesser extent, other metal naphthenates. In fact, calcium naphthenate—a generic term for a deposit which usually contains calcium, sodium, magnesium, iron, and other metal naphthenates, and possibly asphaltene constituents, scale, and other solids—is a troublesome deposit that can form in oil production systems that are handling a crude oil with a high acid number (TAN). The problems caused by calcium naphthenate range from oil treating problems and poor water quality to heavy deposits that can plug lines and valves.
Thermogravimetric analysis has proved to be a suitable tool to investigate calcium naphthenate production and could be used to characterize these solids. The results showed that it is possible to distinguish the compounds produced by specific thermal stability assays. In this report, the synthetic route employed has indicated the formation of different compounds, such as calcium carbonate, calcium sulfate as gypsum, and calcium naphthenate. In the experiments, precipitation of calcium sulfate showed to be dependent on solution pH. Moreover, the reproducibility tests confirmed the qualitative significance in the formation of naphthenates (Moreira and Teixeira, 2009).
1.2.1 Origin
Naphthenic acids are natural constituents of petroleum, where they evolve through the oxidation of naphthenes (cycloalkanes). Initially, the presence of these acidic species was suggested due to process artifacts formed during refining processes, and this may still be the case in some instances. However, it was shown that only a small quantity of acids was produced during these processes (Costantinides and Arich, 1967). Currently, it is generally assumed that acids may have been incorporated into the oil from three different sources: (i) acidic compounds found in source rocks, derived from the original organic matter that created the crude oil (plants and animals), (ii) neo-formed acids during biodegradation (although the high acid concentration in biodegraded oils is believed to be related principally to the removal of nonacidic compounds, leading to a relative increase of the acid concentration levels), and (iii) acids that are derived from the bacteria themselves, e.g., from cell walls that the organisms leave behind when their life cycle is completed (Mackenzie et al., 1981; Behar and Albrecht, 1984; Thorn and Aiken, 1998; Meredith et al., 2000; Tomczyk et al., 2001; Watson et al., 2002; Wilkes et al., 2003; Barth et al., 2004; Kim et al., 2005; Fafet et al., 2008).
This diverse group of saturated monocyclic and polycyclic carboxylic acids can account for as much as 4% (w/w) of crude petroleum (Brient et al., 1995) and represents an important component of the crude oil feedstock as well as waste generated during petroleum processing in some situations (such as the desalting step). Naphthenic acids are also natural constituents of tar sand (oil sand) bitumen and, during the bitumen extraction process, when the alkalinity of the water (pH: approximately 8) promotes solubilization of naphthenic acids (pKa: approximately 5), the acids are solubilized and concentrated in the tailings stream (Rogers et al., 2001, 2002; Headley and McMartin, 2004; Scott et al., 2005).
In terms of the origin of naphthenic acids, biodegradation of hydrocarbons and the resulting decline in crude oil quality is common in reservoirs cooler than approximately 80°C (176°F). Petroleum biodegrading organisms have a specific order of preference for compounds that they remove from oils and gases (Seifert, 1973; Speight, 2014a). Progressive degradation of crude oil tends to remove saturated hydrocarbons first, concentrating heavy polar and asphaltene components in the residual oil. This leads to decreasing oil quality reflected in a lowering of the API gravity while increasing viscosity, sulfur, and metal contents. In addition to lowering reservoir recovery efficiencies, the economic value of the oil generally decreases with biodegradation owing to a decrease in refinery distillate yields and an increase in vacuum residua yields (Wenger et al., 2001; Speight, 2014). Furthermore, biodegradation leads to the formation of naphthenic acid compounds, which increase the acidity of the oil (typically measured as TAN) (Speight and Arjoon, 2012). An increase in the TAN may further reduce the value of the crude oil and may contribute to production and downstream handling problems such as corrosion and the formation of emulsions (see Chapter 3).
Briefly, petroleum biodegradation is the alteration of crude oil caused by living organisms (Conan, 1984). Initially, it was assumed that hydrocarbon degradation only was possible in the presence of oxygen, the processes being carried out by aerobic bacteria (oxygen electron acceptors) (McKenna and Kallio, 1965; Conan, 1984; Waples, 1985). However, anaerobic bacteria also are capable of hydrocarbon degradation in subsurface petroleum reservoirs (Head et al., 2003; Aitken et al., 2004; Huang et al., 2004; Vieth and Wilkes, 2006) and some bacteria can exist under both aerobic and anaerobic conditions (Gaylarde et al., 1999; Grishchenkov et al., 2000; Yemashova et al., 2007). The biodegradation processes are controlled by conditions that support microbial life and suit the specific bacteria, important factors being reservoir temperature, water pH, salinity and nutrient concentrations, and the accessibility to electron acceptors and hydrocarbons (Magot et al., 2000; Peters et al., 2005). Biodegradation has a negative impact on the oil quality and renders both the oil recovery and refining process difficult – the molecular changes that take place in the crude oil feedstock as a result of biodegradation the product oil have an increased viscosity over the initial oil.
Naphthenic acids contribute to oil quality debits and may cause additional processing and downstream handling problems. Bacterial activity is strongly controlled by temperature, but it also may be impacted by formation water salinity, availability of free or combined oxygen, and reservoir characteristics.
Evaluating the decline in hydrocarbon quality associated with biodegradation has become critical in recent years, as offshore drilling has progressed into deeper water depths. In many areas (e.g., offshore West Africa, Brazil, mid-Norway, South Caspian, and eastern Canada), reservoir targets in deep-to-ultra-deep water are shallow, and geothermal gradients are low. These factors make oil quality a major risk because decreased recovery efficiency and oil value compound with higher deep-water operating costs to significantly impact economics, even on major discoveries.
In addition to the concentration of low quality oil components during biodegradation, new compounds can be formed that negatively impact quality. Bacteria appear to manufacture acids, most of which are naphthenic (i.e., cyclic) acids, during the biodegradation of petroleum (Meredith et al., 2000). Because of solubility differences, low molecular weight (C1–C5) acids occur predominantly in associated formation waters (Reinsel et al., 1994) while higher molecular weight (≥C6+) acidic species are concentrated in the oil phase. However, apart from this generalization, the distribution of the various naphthenic acid species in crude oil is not fully understood.
Acid contents are usually monitored as a TAN determined by potentiometric titration as per the ASTM D664 method. This method is wrought with potential interferences and interpretive problems (Piehl, 1988) but it still remains a standard method by which oils are assayed and valued. The TAN generally increases with increasing levels of biodegradation. The current activity of biodegrading organisms may be most important in determining organic acid contents because acids may dissipate rapidly owing to relatively high water solubility and reactivity. In addition, this method measures not only the organic acids but also the acidity generated by hydrogen sulfide, carbon dioxide, magnesium chloride (MgCl2), and calcium chloride (CaCl2) in crude oils and may hydrolyze (Piehl, 1960, 1988).
Elevated naphthenic acid contents (TAN >1 mg KOH/g crude oil) are detrimental to crude oil value because acids cause refinery equipment corrosion at high temperatures (Babaian-Kibala et al., 1993, 1998; Turnbull et al., 1998). This can result in an additional valuation debit. Naphthenic acids and their salts (naphthenates) also may lead to the formation of emulsions upon production of biodegraded oils. Sometimes, these emulsions can be tight and difficult to break by conventional means. The additional expense associated with breaking emulsions, especially on production platform sites in deep water, can further challenge field economics. Low molecular weight organic acids in water often impart very foul odors and can cause wastewater disposal problems in refineries processing some biodegraded oils.
1.2.2 Occurrence
HACs have recently become an important development in the international crude oil. The inclusion of substantial amounts of very high acid crudes is projected to take an increasing share of the rising volume of global oil production. Already in excess of 5 million barrels per day of Atlantic basin, crudes have high acid numbers and are sold at a discount to marker crudes that can be substantial (ESMAP, 2005).
High acid crudes are plentiful in most global regions and are increasing their proportion of the total crude supply—South America is a net exporter of high acid crude and high acid crude blends. North West Europe which has traditionally been a net exporter of high acid crudes is now balanced (increased refinery capacity for high acid crudes) and the crudes are exported to the US East Coast, the US Gulf Coast, the Mediterranean area, and even to the Far East. West African high acid crude production is rapidly increasing and being exported out of the region (Table 1.4). Total global supply of high acid crudes is in excess of 9 million barrels per day (Shafizadeh et al., 2010; Gruber et al., 2012; Handa, 2012; Damasceno et al., 2014).
Table 1.4
High Acid Crudes Available to Various Markets
| Source | Crude |
| North West Europe | Alba |
| Captain | |
| Clair | |
| Grane | |
| Gryphon | |
| Harding | |
| Heidrun | |
| Leadon | |
| Troll blend | |
| South America | Marlim |
| Roncador | |
| Venezuelan blends | |
| West Africa | Ceiba |
| Benguela heavy | |
| Dalia | |
| Kome | |
| Kuito | |
| Lokele | |
| Rosalita |
For example, the Central African Republic of Chad ranks as the 10th largest oil reserve holder among African countries, with 1.5 billion barrels of proven reserves as of January 1, 2013 (http://www.eia.gov/countries/country-data.cfm?fips=cd). Crude oil production in Chad was estimated as 115,000 barrels per day (bbl/d) in 2011 and 105,000 bbl/d in 2012, and almost all of this crude oil was exported via the Chad–Cameroon Pipeline. Furthermore, the Chad Doba blend crude oil is substantially affected by this market movement to HAC—Doba blend is a heavy low sulfur, high acid, crude oil (API ~20.6°, ~0.1% w/w sulfur, TAN ~4.7 KOH/mg).
China has seen substantial increases in high acid crude production in recent years and will continue to dominate output through 2015, most likely with substantial increases in production of Qin Huang Dao (QHD) crude oil (Chevron, 2012a) (Table 1.5). In addition, China’s National Energy Administration has approved a revised development plan (Conoco Phillips) for second phase development of Penglai 19-3 and Penglai 25-6 oil fields in northern Bohai Bay (Juan and Xian, 2009; Tai and Xian, 2011).
Table 1.5
QHD Crude Oil Assay (Chevron, 2012a)
| API gravity | 16.48 |
| Specific gravity | 0.96 |
| Sulfur (% w/w) | 0.28 |
| Nitrogen (ppm) | 4737.29 |
| Acid number (mg KOH/g) | 2.49 |
| Pour point (°C) | −17.97 |
| Characterization factor (K-factor) | 11.76 |
| Viscosity, cSt at 40°C (104°F) | 799.76 |
| Viscosity, cSt at 50°C (122°F) | 378.71 |
| Vanadium (ppm) | 0.51 |
| Nickel (ppm) | 13.01 |
| Microcarbon residue (% w/w) | 7.11 |
| Ramsbottom carbon (% w/w) | 6.11 |
| n-Heptane asphaltene (% w/w) | 0.86 |
In other regions, Australia, which produced minimal acidic crude output in the Wandoo field, will add substantial high acid crude TAN output with the startup of Vincent and Crosby, both moderately high acid crude grades that will be exported. Duri crude oil (Indonesia) (Table 1.6) (Chevron, 2012b) will increasingly be diverted to domestic use, but remains the closest thing to a regional high acid crude marker (Wu, 2010).
Table 1.6
Duri Crude Oil Assay (Chevron, 2012b)
| API gravity | 20.29 |
| Specific gravity | 0.93 |
| Sulfur (% w/w) | 0.21 |
| Nitrogen (ppm) | 3635.70 |
| Acid number (mg KOH/g) | 1.46 |
| Pour point (°C) | 10.79 |
| Characterization factor (K-factor) | 12.13 |
| Viscosity, cSt at 40°C (104°F) | 375.74 |
| Viscosity, cSt at 50°C (122°F) | 205.40 |
| Vanadium (ppm) | 1.35 |
| Nickel (ppm) | 39.28 |
| Microcarbon residue (% w/w) | 8.01 |
| Ramsbottom carbon residue (% w/w) | 7.23 |
| n-Heptane asphaltene (% w/w) | 0.08 |
West African producers have added a number of new HAC since 2004 and overall output of high acid crudes will continue to grow. Angola and Sudan are the main producers of HACs. Sudan will expand substantially the output of high acid crude, particularly for the very acidic Fula crude oil (Dou et al., 2013; Saad et al., 2014). A lack of refining capacity and, in some cases, operational issues, in most of these African market countries will continue to spur export of high acid crudes.
While North Sea overall production will decline, the UK and Norway will experience increases in the output of high acid crudes. Most acidic crude production, such as the Grane crude with an acid number of 2.3 mg KOH/g oil (Statoil, 2012), will continue to be used in NW Europe though the US market receives regular imports of Norwegian cargoes. On the other hand, the output of high acid crudes in Latin America will have an increasing impact on the Asia Pacific crude oil slate—Venezuelan crude oils will continue to appeal to the Chinese and Brazilian for increased sales of high acid crudes. Whether the sales relate to political issues or commercial issues, the next 5 years will see an increase in interregional sales of high acid crudes.
Processing acidic crudes creates corrosion issues to refinery equipment and requires special and expensive technical solutions. Mitigation of process corrosion includes blending, inhibition, material upgrading, and process control (see Chapter 5). Some, but not all, refineries are presently able to refine high acid crudes without suffering serious corrosion problems—to circumvent the effect of high acid crudes, most refiners blend high acid crudes with other crudes before refining. Given that crude is purchased in large parcel sizes, the need to blend one such parcel with multiple parcels of low acid crudes is costly and worthwhile only if there is a substantial discount available for the high acid crude. In the United States, most of the facilities which process heavy sour crude oils and crude oils having a high TAN from Venezuela, Brazil, and Mexico are located on the Gulf Coast. Most of the lighter lower sulfur feedstocks (synthetic crudes) are expected to be shipped to the low- to medium-sulfur refineries in the Mid-Continent, Midwest, and Great Lakes regions of the United States (Baker Hughes, 2010). The refineries which can process high acid crudes are then able to benefit from the existence of the price discount.
The current potential buyers of high acid crudes include: (i) refineries with specialized metallurgy, (ii) large refineries that can dilute acidic crude through blending, (iii) refiners who buy high acid crude when discounted with sufficient specialized facilities to handle these grades, (iv) specialized, non-processing utilizations, (v) risk-adverse refiners who will only occasionally experiment with high TAN grades, and (vi) large refineries buying discounted acidic crude with the plan to use the resid as feedstock for a catalytic cracking unit. Refiners can handle acidic crudes safely through three main methods—dilution (i.e., blending with nonacidic crude), chemical injection, to neutralize acidity, and through the selection and use of specialized materials for the refinery, particularly special alloy steels.
However, the occurrence of naphthenic acids in crude oil is not the only issue when crude pricing is determined. The price differentials between the various crudes depend on a number of factors, including (i) the demand for various petroleum products, (ii) the costs and availability of refineries able to run various crudes to produce the products most in demand, (iii) refinery capacity utilization, (iv) transportation costs, and (v) the relative supply of the different crudes. If the demands for all petroleum products increased proportionately, and all product prices and the general crude price also increased proportionately, then those crudes producing the largest proportion of high value products would increase in price relative to those crudes with a lower proportion of high value products. This effect would be magnified if the demand for the higher value products increased relatively more, so that the price of high value products rose faster than that of low value products.
For example, the diesel fractions derived from Athabasca bitumen and the syncrude oil have low cetane numbers (<30) and very high sulfur content and nitrogen content. Therefore, it is difficult to meet both road cetane and ultralow sulfur specifications on bitumen-derived synthetic crude oil. High nitrogen content also inhibits desulfurization, particularly with respect to dibenzothiophene. In handling these low quality crudes, modifications of the distillate, kerosene, and naphtha hydrotreater must be addressed. The naphtha reformer must also be adjusted since bitumen-derived naphtha has high naphthene content and aromatics content.
1.3 Total Acid Number
Once the presence of acidic species has been determined for crude oil, the next step is to define the crude in terms of acidity. This is done through determination of the acid number, which is measured in units of milligrams of potassium hydroxide required to neutralize a gram of oil. The TAN can be used to further subdefine the crude as high acid crude or low acid crude.
Regardless of the source, the acids present in the oil cause much corrosion in the refinery equipment. The most common current measures of the corrosive potential of a crude oil are the neutralization number or total acid number. These are total acidity measurements determined by base titration. Commercial experience reveals that while such tests may be sufficient for providing an indication of whether any given crude may be corrosive, the tests are poor quantitative indicators of the severity of corrosion—for the same TAN, molecular size and structure of the acid also have an important influence (Turnbull et al., 1998).
However, the TAN is expressed in terms of milligrams of potassium hydroxide per gram (mg KOH/g) and is not specific to a particular acid but refers to all possible acidic components in the crude, and is defined by the amount of potassium hydroxide required to neutralize the acids in one gram of oil. A TAN >0.5 mg is (arbitrarily) considered to be high. As an example, Wilmington and Kern crude oil have a TAN ranging from 2.2 to 3.2 mg KOH/g crude oil, respectively.
However, some acids are relatively inert and, thus, the TAN does not always represent the corrosive properties of the crude oil and, furthermore, different acids will react at different temperatures—making it difficult to pinpoint the processing units within the refinery that will be affected by a particular HAC. Nonetheless, HACs contain naphthenic acids, a broad group of organic acids that are usually composed of carboxylic acid compounds. These acids corrode the distillation unit in the refinery and form sludge and gum which can block pipelines and pumps entering the refinery. The impact of corrosive HACs can be overcome by blending higher and lower acid oils, installing or retrofitting equipment with anticorrosive materials, or by developing low temperature catalytic decarboxylation processes using metal catalysts such as copper. Many California refineries already process high acid crude (Sheridan, 2006).
Although the TAN value is used to define which crudes are high acid crudes, the number is not a reliable indicator of the potential of the crude oil for causing problems with reliability and operations in the refinery. Many acidic species are included in the TAN of the oil and the number actually represents (i) all organic acids, such as naphthenic acids and any other low molecular weight organic acids and (ii) any acids present in the crude that have been added during the production process (Scattergood and Strong, 1987; Craig, 1995, 1996; Hau and Mirabal, 1996; Tebbal and Kane, 1996; Tebbal et al., 1996; Lewis et al., 1999; Kane and Cayard, 2002; Speight, 2014). Typically found are naphthenic acids, which are organic, and also mineral acids such as hydrogen sulfide (H2S), hydrogen cyanide (HCN), and carbon dioxide (CO2) can be present, all of which can contribute significantly to corrosion of equipment. Even materials suitable for sour service do not escape damage under such an onslaught of aggressive compounds. Again, because of cost considerations, a trend towards a preference for crude oils with a higher TAN is noticeable.
Current methods for the determination of the acid content of hydrocarbon compositions are well established (ASTM D664) which include potentiometric titration in nonaqueous conditions to clearly defined end points as detected by changes in millivolts readings versus volume of titrant used. A color indicator method (ASTM D974) is also available. However, the ASTM D974 test method is an older method and used for distillates while the ASTM D664 test method is more accurate but measures acid gases and hydrolyzable salts in addition to organic acids. These differences are important on crude oils but less significant on distillates and the naphthenic acid titration (NAT) test method is more precise for quantifying the naphthenic acid content (Haynes, 2006). Both methods (ASTM D664 and ASTM D974) are susceptible to interference for all or any of the following: inorganic acids, esters, phenolic compounds, sulfur compounds, lactones, resins, salts, and additives such as inhibitors and detergents interfere with both methods. Thus, these ASTM methods do not differentiate between naphthenic acids, phenols, carbon dioxide, hydrogen sulfide, mercaptans, and other acidic compounds present in the oil.
• Potentiometric titration:
In this method (ASTM D664), the sample is normally dissolved in toluene and propanol with a little water and titrated with alcoholic potassium hydroxide (if sample is acidic). A glass electrode and reference electrode are immersed in the sample and connected to a voltmeter/potentiometer. The meter reading (in millivolts) is plotted against the volume of titrant. The end point is taken at the distinct inflection of the resulting titration curve corresponding to the basic buffer solution.
• Color indicating titration:
In this test method (ASTM D974), an appropriate pH color indicator (such as phenolphthalein) is used. The titrant is added to the sample by means of a burette and the volume of titrant used to cause a permanent color change in the sample is recorded from which the TAN is calculated. It can be difficult to observe color changes in crude oil solutions. It is also possible that the results from the color indicator method may or may not be the same as the potentiometric results.
Test method ASTM D3339 is also similar to ASTM D974, but is designed for use on smaller oil samples. ASTM D974 and D664 use (approximately) a 20 g sample and ASTM D3339 uses a 2.0 g sample. However, both methods use a color change to indicate the end point. ASTM D1534 is designed for electric insulating oils (transformer oils), where the viscosity will not exceed 24 cSt at 40°C (104°F).
The risk with any of these methods is the insufficiency of a specific test method to produce meaningful or realistic data. For example, the ASTM D974 test method is an older method and used for distillates while the ASTM D664 test method is more accurate but measures acid gases and hydrolyzable salts in addition to organic acids. Moreover, inorganic acids, esters, phenolic compounds, sulfur compounds, lactones, resins, salts, and additives such as inhibitors and detergents may not be amenable to the procedure and may interfere with the method. In addition, many methods do not differentiate between naphthenic acids, phenols, carbon dioxide, hydrogen sulfide, mercaptans, and other acidic compounds present in the oil. In addition, the TAN values as conventionally analyzed and a are no longer considered to be a reliable indicator of corrosivity (Rikka, 2007).
These differences are important for refining crude oil but may be considered to be less significant distillates—the NAT method is more precise for quantifying the naphthenic acid content (Haynes, 2006).
The UOP 565 test method (http://www.astm.org/Standards/UOP565.htm) is used to determine the acid number of petroleum products, petroleum distillates, and similar materials by potentiometric titration. Inorganic acids, organic acids, mercaptans, and thiophenols respond to this analysis, but their respective salts do not. For naphthenic acids, it is often preferable to include the salts in the measurement. Therefore, a procedure is also included for the determination of sodium naphthenate salts. The typical range for acid number determination is 0.002–5 mg KOH/g of sample, although higher concentrations can be accommodated.
In addition, there is another test method, the UOP 587 test method (http://www.pngis.net/standards/details.asp?StandardID=UOP+587%3A1992) which is used for determining the acid number of petroleum products, petroleum distillates, and other hydrocarbons by colorimetric titration. Inorganic acids, organic acids, mercaptans, and thiophenols respond to this analysis, but their respective salts do not. This method is limited to light colored distillates. For dark colored samples, the potentiometric procedure in UOP Method 565 (http://www.astm.org/Standards/UOP565.htm) is preferred.
The acid number of a sample can be determined on an as-received basis or on a mercaptan and thiophenol-free basis. The method can also be used to determine naphthenic acids, including sodium naphthenates (soaps) in caustic washed hydrocarbons. For an estimated relative molecular mass of 130, the range of detection for naphthenic acids is 5–250 ppm. The latter two procedures apply almost exclusively to low boiling kerosene and low boiling gas oil where it is assumed that the organic acids are entirely naphthenic.
A new method is available for rapid measurement of TAN and boiling point (BP) distribution for petroleum crude and products. The technology is based on negative ion electrospray ionization mass spectrometry (ESI-MS) for selective ionization of petroleum acid and quantification of acid structures and molecular weight distributions. A chip-based nano-electrospray system enables microscale (<200 mg) and higher throughput (20 samples/h) measurement. Naphthenic acid structures were assigned based on nominal masses of a set of predefined acid structures. Stearic acid is used as an internal standard to calibrate ESI-MS response factors for quantification purposes. With the use of structure–property correlations, BP distributions of TANs can be calculated from the composition. The rapid measurement of TAN BP distributions by ESI is demonstrated for a series of high acid crudes and distillation cuts. TANs determined by the technique agree well with those by the titration method. The distributed properties compare favorably with those measured by distillation and measurement of the TANs of corresponding cuts (Qian et al., 2008).
Still another method advocates the use of extraction/esterification/mass spectrometry and provides an analysis of C10+ naphthenic acids. However, lower molecular weight acids can be lost in the esterification step (Jones et al., 2001).
Finally, the iron powder test is a method of measuring naphthenic acid corrosion potential and produces results that agree with existing knowledge about this phenomenon (Hau et al., 1999, 2003). The higher the acid content corresponds to greater corrosivity has been observed in the field and in laboratory test results. Advantageously, the iron powder test has revealed that crude oil samples that have the same acid numbers do not show the same corrosivity.
The method has also shown that crude oil samples having higher acid number values can exhibit less corrosivity than other crudes having lower acid numbers—unlike potassium hydroxide, which does not only react with naphthenic acids but also with other compounds such as hydrolyzable salts, iron naphthenates, inhibitors, and detergents, iron powder is more likely to react with all those species also capable of producing corrosion on actual steels. Naphthenic acids present are stronger and expected to produce a larger amount of dissolved iron than in another oil sample having weaker organic acids.
Because of the confusion that can exist when attempting to relate TAN to corrosivity, there has been an interest in developing methods for the analysis of naphthenic acids. For example, the composition of naphthenic acid fraction is helpful in identification of oil source maturation (Headley et al., 2002; Meredith et al., 2000) as well as for fingerprinting fuel spills in the environment (Rostad and Hostettler, 2007). The overall chemical and physical properties of the naphthenic acid fraction (as obtained by extraction from the source) may also vary (Clemente et al., 2003a, b; Headley and McMartin, 2004). Additionally, the need to assess the corrosivity and toxicity including their fate, transport, and degradation has heightened the need for improved characterization of the components of naphthenic acids is necessary since the corrosive and toxic effects are often structure specific (Clemente and Fedorak, 2005).
However, many analytical methods that have been developed to characterize naphthenic acids tend to be semiquantitative, and lack the ability to identify the individual isomers and their respective properties. Thus, a reliable and accurate analytical method is needed to meet the major challenges in devising a suitable test method and these are: (i) quantitation of the total concentration of naphthenic acids in a sample, (ii) characterization of the structures of the compounds in the complex, poorly defined mixtures obtained using various sampling protocols, (iii) determination of the concentration of the true naphthenic acids (as indicated by the definition) and other components found in the mixture obtained following a sampling protocol, and (iv) assessment of the corrosivity (and toxicity) of each of the component types found in the fraction.
1.4 Properties
The initial observations about naphthenic acids in petroleum and naphthenic acid corrosion date back to the early part of the twentieth century (Ney et al., 1943; Derungs, 1956) and have continued to affect refinery operations to the present time (Speight, 2014b). The so-called opportunity crudes with a high naphthenic acid content continue to be exploited (in ever-increasing amounts) and refined (Johnson et al., 2003; Blume and Yeung, 2008). Naphthenic acid corrosion is complicated because of the complexity of the naphthenic acid mixture (and the potential range of structural types in the mixture) (Tables 1.1–1.3) found in crudes from the various sources. Sometimes, the distribution of naphthenic acids is grouped according to their BP, with an implication that naphthenic acids with different BPs lead to different corrosivity (Clemente et al., 2003a, b; Messer et al., 2004).
The prerequisite for designing practical and highly efficient naphthenic acid removal processes (see Chapter 5) is to determine the existing forms, properties, character, and distribution of naphthenic acids (Cai and Tian, 2011). Numerous efforts have been assigned to the determination and analysis of the naphthenic acid fraction of crude oils, with compounds identified including linear fatty acids, isoprenoid acids, as well as monocyclic, polycyclic, and aromatic acids. In addition, other groups of compounds which can influence the acidity of crude oil include inorganic acids, such as some compounds of calcium and magnesium, which are difficult to be removed in the desalting process, and low molecular weight alkyl phenols, which also occur widely in crude oils (Speight, 2014a).
1.4.1 Chemical Properties
Despite the reports of presence of compounds in petroleum acidic fractions that do not solely contain the carboxylic acid functional group, most of the research on petroleum acids comprises the so-called naphthenic acids. The term naphthenic acids is commonly used to describe an isomeric mixture of carboxylic acids containing one or several saturated alicyclic rings. Acidic crude oils are generally considered as problematic from an oil quality point of view. The acids cause corrosion problems in the refinery processes and due to their toxicity, they also represent a pollution source in refinery wastewaters.
1.4.1.1 Chemical Structure
Naphthenic acids are a family of carboxylic acid surfactants with varying properties (Tables 1.1–1.3 and 1.7), primarily consisting of cyclic systems that originate from petroleum source material (Brient et al., 1995; Robbins, 1998; Cai and Tian, 2011; Speight, 2014a). The members of this chemical group are composed predominately of alkyl-substituted cycloaliphatic carboxylic acids with smaller amounts of acyclic aliphatic (paraffinic or fatty) acids. Aromatic olefin acids, hydroxyl acids, and dibasic acids are also present as minor components of the naphthenic acid fraction. The cycloaliphatic acids include single rings and fused multiple rings and the carboxyl group is bonded or attached to a side chain or to a cycloaliphatic ring (Dzidic et al., 1988; Fan, 1991).
Table 1.7
Varying Properties of Naphthenic Acids (Headley and McMartin, 2004)
| Parameter | General Characteristic |
| Color | Pale yellow, dark amber, yellowish brown, black |
| Odor | Primarily imparted by the presence of phenol and sulfur impurities; musty hydrocarbon odor |
| State | Viscous liquid |
| Molecular weight | Generally between 140 and 450 amu |
| Solubility | <50 mg/l at pH 7 in water |
| Completely soluble in organic solvents | |
| Density | Between 0.97 and 0.99 g/cm3 |
| Refractive index | Approximately 1.5 |
| pKa | Between 5 and 6 |
| Log Kow (octanol water partition coefficient) | Approximately 4 at pH 1 |
| Approximately 2.4 at pH 7 | |
| Approximately 2 at pH 10 | |
| Boiling point | Between 250°C and 350°C |
Note: All values vary greatly with naphthenic acids source and composition. Values also vary between native and bitumen-extracted compounds.
The components of naphthenic acids are commonly classified by their structures and the number of carbon atoms in the molecule. The polarity and nonvolatility of naphthenic acids increase with molecular weight, which imparts various chemical and physical properties on individual constituents (Robbins, 1998; Headley et al., 2002; Headley and McMartin, 2004; Clemente et al., 2003a, b). However, as a group the naphthenic acids have chemical and physical characteristics that can be used to describe the overall mixture.
1.4.1.2 Acidity
Naphthenic acids confer acidic properties on crude oil and the extent of the acidity is expressed as the TAN, which is the number of milligrams of potassium hydroxide required to neutralize one gram of crude oil (ASTM D3339) (Table 1.8). For convenience, HACs, also called high total acid number (high TAN) crude oils, are crude oils which typically have an overall acidity (expressed as the TAN) that exceed some specified arbitrary limit. Typically crudes with a TAN 0.5 mg KOH/g oil or higher are specified as high acid crudes, and they are known to create problems in a refinery. Although not all acidic components in crude are potentially corrosive, refineries find it preferable and less amenable to corrosion if the crude oil feedstock has a TAN <0.5 mg KOH/g crude.
Table 1.8
Comments on Testing for Naphthenic Acids
| Origin | Naphthenic acids are natural chemical species occurring in some crude oils |
| Effects | Naphthenic acids may cause operational problems such as foaming in the desalter or other units |
| Measurement units | Naphthenic acids are measured as milligrams of KOH per gram of crude oil |
| Desired levels | The desired level of naphthenic acids in the crude oil is <0.05 mg KOH/g oil |
| Degree of accuracy | The acid content of a crude oil may be determined to be ±0.02 mg KOH/g oil, which includes species other than naphthenic acids |
The data for the TAN derived from either (i) potentiometric titration (ASTM D664) or (ii) color indicator titration methods (ASTM D974) are reported in terms of milligrams of KOH per gram of oil sample. The TAN is generally considered to be a measure of all acidic components, including naphthenic acids and sulfur compounds. The TAN has been used to assess the potential for corrosion problems in a crude oil refinery. Values of the TAN in the range of 0.1–3.5 mg KOH/g are common but can be as high as 10.0 for hydrocarbon fractions isolated or produced from crude oil. The basis for the increase in corrosive effects with HAC is presumed to be due to the availability of the carboxylic acid group to form metal complexes.
Conversely, the total base number (TBN) is determined by titration with acids and is a measure of the amount of basic substances in the oil always under the conditions of the test (ASTM D2896). Both the TAN and the TBN are a numerical representation of the acidic or basic species in a crude oil. The numbers are not mutually interchangeable in any form and should not be considered to be a reliable guide to the chemical properties and behavior of crude oil.
HACs are usually placed in the class of crude oils known as opportunity crudes (Table 1.9), which are typically offered at a discount when compared to conventional crude oils and even, on occasion, when compared to heavy crude oil. Opportunity crudes may have various combinations of (i) high sulfur content on the order of >0.7–1.0% (w/w), (ii) high nitrogen content, (iii) high aromatics content, (iv) low API gravity, on the order of <26–28°, (v) high vacuum residuum content, (vi) high viscosity, and (vii) high acidity, with a TAN exceeding 0.5 or 1.0 mg KOH/g (Table 1.7).
Table 1.9
| Crude type | Properties | Concerns |
| Heavy sour crude | API <26° | Yield slate |
| >1 wt% sulfur | Increased delta coke causes lower conversion and higher regeneration temperature in FCC | |
| Contaminants may harm catalysts | ||
| Corrosion problems in CDU | ||
| Fouling problems | ||
| Extra-heavy crude or bitumen | API <10° | Low cetane index for diesel |
| Typically also have high metals content | Large amount of resid material | |
| Viscosity 100–10,000 cP at 60°F (15.6°C) for extra-heavy oil | Large amount of contaminants may harm catalysts | |
| Viscosity >10,000 cP at 60°F (15.6°C) for bitumen | Fouling problems | |
| High acid crude | TAN >0.5 mg KOH/g | Increased corrosion |
| Typically also heavy, API <26° | Poor salt removal and separation of oil and water | |
| Fouling reduces plant capacity | ||
| Degradation of catalyst activity by calcium | ||
| Low cetane index for diesel | ||
| May impact product specifications |
In some crude oils, the naphthenic acids are the main oxygen-containing components of petroleum (0.5–3.0% w/w), from which they are extracted in the form of salts (naphthenates) by means of an aqueous solution of an alkali. Naphthenic acids are viscous, colorless liquids that turn yellowish upon standing. The BP is on the order of 220–300°C (430–570°F) and the pour point is usually <80°C (176°F). Naphthenic acids are generally insoluble in water but dissolve readily in petroleum products and other organic solvents. Chemically, these constituents exhibit properties that are characteristic of carboxylic acids. Other less desirable properties relate to the corrosivity of these acids.
Furthermore, when high acid crudes are processed, the naphthenic acid corrosion and sulfur corrosion occur together mainly in distilling towers and their adjacent transfer lines. The two corrosive groups, i.e., naphthenic acids and sulfur compounds, influence each other and their effect cannot be simply separated (Laredo et al., 2004). Both are very reactive at high temperatures while naphthenic acid seems to be most aggressive at high velocity encountered in refinery transfer lines. Thus, processing high acid crudes is not always a profitable operation and benefiting from the least expensive crude oils in the market such as high acid crudes, heavy sour crudes, extra-heavy oil, and tar sand (oil sand) bitumen can keep refining margins high. On the other hand, not all refineries can handle crude oil with a high corrosion propensity and a disproportionate amount of bottom-of-the-barrel fractions.
Thus, HACs will have an adverse impact on refinery reliability and operations with corrosion, desalter problems, fouling, catalyst poisoning, product degradation, and environmental discharges. Corrosion caused by such crude oils must be managed by (i) predicting corrosion behavior, (ii) relative risk levels of processing such crudes, (iii) inspection and monitoring methods to identify specific areas that are at risk of naphthenic acid corrosion and to verify that control methods are being used effectively, and (iv) applying suitable corrosion control methods. There are also alloys that appear to be even more corrosion resistant than existing favorites (e.g., 316 SS and 317 SS) (Yeung, 2006). Modifying or removing naphthenic acids will be accomplished via neutralization, decarboxylation, hydrotreating, and extraction (see Chapter 5).
A major concern with processing such crude (and heavy crude oils) is blending and mixtures, since it is common for compatible crudes, such as Louisiana Light-Sweet, West Texas Intermediate, and Alaskan North Slope, from multiple fields to be mixed in pipeline systems, since a lot of refineries are short on crude tankage. The composition of such crude oils is different—incompatibility can occur not only between the easily recognized high asphaltene crude oil and high paraffinic crude oil as well as between HAC and high paraffinic crude oil.
Crude oil incompatibility and the formation of a separate immiscible phase when crude oils are blended can lead to fouling in the desalter, in heat exchangers, and in pipestill furnace tubes. Therefore, it is important to use prerefining test methods (performed by the seller or the buyer) to predict the proportions and order of blending of oils that will prevent incompatibility prior to the purchase of the crudes, recognizing that the test method may provide data that include molecular species other than naphthenic acids (Table 1.7). In either case, it is advisable that the buyer be advised by the seller of the quality of the crude oil that is being purchased.
In addition to taking preventative measures for the refinery to process these feedstocks without serious deleterious effects on the equipment, refiners will need to develop programs for detailed and immediate feedstock evaluation so that they can understand the qualities of a crude oil very quickly and it can be valued appropriately and management of the crude processing can be planned meticulously.
In addition, naphthenic acids have been found to cause the formation of soaps. The alkali metals soaps/salts, sodium and potassium naphthenates are water soluble and water dispersible, giving tight emulsions and poor oil-in-water qualities. Naphthenic acid soaps of the alkaline earth metals are insoluble in normal oilfield brines, with a pH >7 at normal upstream process temperatures.
Finally, the toxicity of naphthenic acids is often associated with the surfactant characteristics (Headley and McMartin, 2004). However, since hundreds of the acidic compounds are found in the naphthenic acid fraction, it has not conclusively established which specific naphthenic acids are the most toxic. Since no two crude oil reservoirs are precisely exactly the same, the content and complexity of naphthenic acids in crude oils are also not exactly the same. Thus, toxicity does not necessarily correlate directly to the naphthenic acid concentration, but is more a function of content and complexity (Headley and McMartin, 2004).
1.4.2 Physical Properties
Naphthenic acids recovered from refinery streams occur naturally in the crude oil and are not formed during the refining process. Heavy crudes have the highest acid content, and paraffinic crudes usually have low acid content. Although the presence of naphthenic acids has been established in almost all types of crude oil, only certain naphthenic- and asphalt-based crudes contain amounts that are high enough to require treatment in order to meet product specifications (US EPA, 2012).
Naphthenic acids are obtained by caustic extraction of petroleum distillates, primarily kerosene and diesel fractions. In addition to reducing corrosion in the refinery, the caustic wash of the distillates is necessary to improve the technical properties, storage stability, and odor of the finished kerosene and diesel fuels. The commercial production of naphthenic acid from petroleum is based on the formation of sodium naphthenates which occurs when the petroleum distillates are treated with sodium hydroxide caustic. Since this reaction occurs in situ, sodium salts of naphthenic acids are considered an intermediate stream in the production of refined naphthenic acid. The sodium naphthenate-containing solutions contain approximately 5–15% (w/w) sodium naphthenate, 0–0.5% (w/w) sodium mercaptide (RS−Na+), and 3–4% (w/w) sodium hydroxide in water with a highly alkaline pH (pH >12). These caustic solutions are typically sent to specialized facilities in which they undergo further processing to recover the naphthenic acids.
1.4.2.1 Melting Point
Because naphthenic acids are not pure chemicals, the melting point characteristics of these complex substances vary with the hydrocarbon composition of their make-up. Based on data available in commercial product specifications and Material Safety Data Sheets (MSDS), substances produced for commercial use have melting points that fall in the range from −35°C to +2°C (−31 to 36°F) (US EPA, 2012).
1.4.2.2 Boiling Point
Because these substances are not pure chemicals, the BP characteristics of naphthenic acids and their salts vary according to the hydrocarbon component make-up of the complex substances in which they are found. Based on data available in commercial product specifications and MSDS, substances produced for commercial use have BPs that fall in the range from 140 to 370°C (285 to 700°F) (US EPA, 2012).
1.4.2.3 Solubility
Naphthenic acids can be very water soluble to oil soluble depending on their molecular weight, process temperatures, salinity of waters, and fluid pressures. In the water phase, naphthenic acids can cause stable reverse emulsions (oil droplets in a continuous water phase). In the oil phase with residual water, these acids have the potential to react with a host of minerals, which are capable of neutralizing the acids. The main reaction product found in practice is the calcium naphthenate soap (the calcium salt of naphthenic acids).
Chemically, naphthenic acids are weak acids having pKa values of approximately 5–6 (Brient et al., 1995; Havre, 2002). As the pH of a solution of naphthenic acids increases above the pKa value, a greater proportion of the constituents are ionized and exist in the dissolved phase of the aqueous medium (Havre, 2002). Therefore, alkaline solutions increase a naphthenic acid’s solubility, and acid solutions decrease solubility (Havre, 2002). Product literature references have cited narrative statements such as very low water solubility or only slightly soluble in water.
1.4.2.4 Interfacial Properties
Crude oil components that are surface active (at the boundary between liquid/solid or liquid/gas) and interfacial active (in the interface between two liquids) span over a large range of chemical structures and molecular weights. Asphaltene constituents and resin constituents, including naphthenic acids, are examples of petroleum constituents that display such properties, thus acting as natural surfactants (Seifert and Howells, 1969; Hoeiland et al., 2001; Langevin et al., 2004; Poteau et al., 2005). Surfactant molecules are amphiphilic, meaning that they have both hydrophilic and hydrophobic parts in the molecules, and for this reason adsorb strongly at interfaces (Pashley and Karaman, 2004). Oil/water interfacial active compounds typically reduce the interfacial tension between the two phases and enhance stabilization of water-in-oil (w/o) emulsions. The formation of stable w/o emulsions is generally undesirable and causes serious challenges in petroleum production in terms of separation and refining processes (Sjöblom et al., 2003; Bennett et al., 2004; Ese and Kilpatrick, 2004).
Surface active naphthenic acids in crude oils are also important for reservoir production challenges (Sjöblom et al., 2003; Bennett et al., 2004; Ese and Kilpatrick, 2004). Although the processes involved are complex and still not well understood, polar compounds present in crude oils are generally assumed to be involved in adsorption interactions or deposition mechanisms that take place at the crude oil/brine/rock interface. These surface active components may contribute to wettability alteration of the rock from initial water wet to less water wet or oil wet reservoirs.
1.4.2.5 Environmental Effects
Naphthenic acids are toxic to aquatic algae and other microorganisms—naphthenic acid molecules possess hydrophilic and hydrophobic functional groups which allow these molecules to penetrate into cell membranes and disrupt cellular function, eventually resulting in cell death (MacKinnon and Boerger, 1986; Frank et al., 2008, 2009) and it has been shown (Herman et al., 1994) show that acute toxicity of tar sand (oil sand) process water by natural processes is reduced within 1 year while the removal of chronic toxicity requires 2 to 3 years.
The degradation and detoxification rates have been shown to be related to structure and the same relationship might be expected for corrosion and structure. Thus, toxic effects do not relate directly to the concentration of naphthenic acids but are more a function of content and complexity of naphthenic acid constituents (Brient et al., 1995; Lai et al., 1996; Rogers et al., 2002). Unfortunately, because of the inability of the various test methods and test protocols to differentiate between the individual structures of the naphthenic acid constituents, it cannot be conclusively established which specific naphthenic acids are the most toxic (and the most corrosive) due mainly to the presence of hundreds of these compounds in the naphthenic acid fraction.
1.4.2.6 Biodegradation
Naphthenic acids are amenable to microbial utilization similar to other hydrocarbon compounds—certain microorganisms are capable of degrading complex mixtures of commercial sodium salts of naphthenic acids as well as mixtures of extracted naphthenic acids (Herman et al., 1993, 1994; Clemente et al., 2004; Clemente and Fedorak, 2005).
Although rates of biodegradation may be affected by steric factors related to the numbers of cycloalkane rings or the alkyl constituents on the ring structure, microbial populations respond to naphthenic acid substrates through increased carbon dioxide production, oxygen consumption, and enhancement of metabolism with the addition of nutrients. With single ring naphthenic acids, biodegradation of both the ring and side chain acid has been shown to occur (Herman et al., 1993, 1994). As the number of cycloalkane rings increase, it may be inferred from what is known about degradation of multi-ring naphthenes that biodegradation rates may slow, but these substances will degrade given time (Bartha and Atlas, 1977; Clemente et al., 2004; Clemente and Fedorak, 2005).