March 2017

Special Focus: Corrosion Control

New method to measure TAN of crude oil and refinery distillation fractions

Many refiners look at discounted opportunity crudes as a way to improve their margin spread. The growing varieties of discounted opportunity crudes on the market contain certain risks for the purchaser, such as high naphthenic acid or sulfur content.

Many refiners look at discounted opportunity crudes as a way to improve their margin spread. The growing varieties of discounted opportunity crudes on the market contain certain risks for the purchaser, such as high naphthenic acid or sulfur content.

Sulfur compounds and naphthenic acids are among the many species that contribute to the corrosive nature of crude oils and refined fractions. Therefore, opportunity crudes with high naphthenic acid and sulfur content carry an ongoing risk of increased corrosion. The refiner must balance the cost benefit vs. the risk, and the cost of corrosion control, when processing these crudes.

Occurrence of naphthenic acids

Naphthenic acids are found in many types of crude oil, and can be present in varying concentrations. They are found in crudes of diverse global origin, including those from the US West Coast, Venezuela, China, India, Mexico, Brazil, West Africa, the North Sea, Western Canada and other regions.

The broader availability and higher volume of naphthenic acid-containing crudes increase the risk of experiencing high-temperature corrosion of equipment in refinery operations. The atmospheric and vacuum distillation columns, side strippers, furnaces, piping and overhead systems are particularly at risk.

Naphthenic acid and sulfur corrosion

The link between naphthenic acids and refinery corrosion was established by W. A. Derungs,1 who noted that it was difficult to differentiate between sulfide and naphthenic acid corrosion. Both produce high corrosion rates at elevated temperatures.

The mechanism of corrosion from combined naphthenic acid and sulfur content is described in Eqs. 1–3.2–4

Fe + 2RCOOH , Fe(RCOO)2 + H2              (1)

Fe + H2S , FeS + H2                               (2)

Fe(RCOO)2 + H2S , FeS + 2RCOOH          (3)

In Eq. 1, iron naphthenates are formed from the reaction of naphthenic acids with steel. As they are soluble in oil, the iron naphthenates are carried in the fluid flow. Simultaneously, hydrogen sulfide (H2S) or other sulfide-containing species react with the steel to form an iron sulfide coating on the surface (Eq. 2). In Eq. 3, H2S reacts with the iron naphthenates to form iron sulfide and liberate the naphthenic acids.

While these three reactions form the recognized mechanism of naphthenic acid in sulfur-containing crudes, naphthenic acid corrosion is, in fact, more complex and affected by many factors, such as temperature and velocity, as well as acid and sulfur content.5 Corrosion risk from naphthenic acids is greater at process temperatures greater than 200°C. At operating temperatures greater than 420°C, naphthenic acids are believed to break down into shorter-chain organic acids. These acids can end up in distillation fractions, causing concern about their corrosivity.6 As the operating process temperature increases, so does the possibility of increased corrosion rate due to these short-chain organic acids.

Physical parameters affecting corrosion

Separately, flow-induced wall shear stress can influence the corrosion by naphthenic acid and sulfur species. Refinery units with process stream flow velocities greater than 2.7 m/sec and areas of high turbulence are more susceptible to naphthenic acid corrosion.

A thin film of iron sulfide—formed through the reaction of H2S in crude and steel refinery units—protects the steel from naphthenic acid attack. High-velocity flow and turbulence can, however, dissolve the sulfide film, leaving the metal vulnerable to attack by naphthenic acid.

Desalter upsets caused by naphthenic acids

In the crude oil desalter, naphthenic acids can cause upsets through the formation of emulsions. As the pH of the water inside a desalter increases, naphthenic acids can form very stable sodium naphthenate emulsions. Emulsions must be broken to restore the efficiency of the desalter and reduce fouling.

Corrosion control: Monitoring the acid number

To control corrosion in the processing of crude oil, the acid number and sulfur content of the crude oil or refinery fractions are measured. The total acid number (TAN) is defined as the total acidity—i.e., the amount of potassium hydroxide in mg required to neutralize 1 g of sample.

It is common to find crude or traded fractions, such as vacuum gasoil (VGO), with acid numbers up to 4 mg KOH/g. Most crude or refinery fractions have an acid number of less than 1 mg KOH/g. Experience from refineries and corrosion studies shows elevated corrosion risk when the naphthenic acid content is greater than 0.5 mg KOH/g in crude, and greater than 1 mg KOH/g in fractions. If the TAN of a crude or fraction exceeds these values, then it is considered to be a high-acid-number stream.

Until the release of TAN standard ASTM International (ASTM) D8045, the TAN of crude oil and fractions was estimated using potentiometric method ASTM D664. This test method was originally developed for the analysis of new and used lubricants, and presents the analyst with a number of analytical challenges when it is applied to crude oil and fractions.

For example, insufficient dissolution of crudes and fractions in the titration solvent can pose a problem: Asphaltic, paraffinic (waxy) and bitumen materials are not all readily dissolved in the titration solvent stipulated by the D664 method. When the sample is not fully dissolved, the titrant cannot react with all of the acid contained in the sample. Also, the undissolved sample forms a coating on the glass membrane of the electrode in the titration cell, reducing its ability to accurately sense voltage changes during the titration, and subsequently leading to imprecision and poor accuracy.

A colorimetric titration method, namely ASTM D974, has been used to measure some clear refinery fractions. This test method cannot measure crudes and front-end refinery fractions due to their intrinsically dark color when dissolved in the titration solvent.

A new method for determining acid number

Over the past decade, the industry has been working to overcome the sample and method challenges. One company has developed an improved, reliable method to measure acidity in the challenging matrices of crude and refinery fractions. Overcoming the challenges of analysis for both crude and refined products, this cooperatively developed titration method, released by ASTM, is based on thermometric endpoint detection.

Thermometric titration measuring principle

Previous acidity measurements of crudes and fractions, according to ASTM D664, used a potentiometric titration in which a pH electrode detects the reaction between the titrant and the naphthenic acid. During the titration, the sensor often becomes coated with heavier fractions that are difficult to dissolve in the titration solvent stipulated by the standard, leading to measurement imprecision.

The new method, described in ASTM D8045, uses a thermometric sensor to overcome this issue in two ways. First, there is no glass membrane to coat. Second, the analyst can vary the solvent composition to aid the dissolution of heavier crudes, such as bitumen.

The thermometric sensor and supporting proprietary data analysis algorithms perform well in non-aqueous titration of acidity in crude. The sensor employs a thermistor for precise temperature measurements in the titration vessel. The neutralization reaction of naphthenic acid is exothermic; therefore, the temperature increases over the course of the reaction.

To obtain a sharp discontinuity in the temperature curve at the endpoint, a thermometric indicator that reacts endothermically with excess hydroxide after the endpoint is added to the sample solution. The thermometric titration gives an inverted V-shaped curve, as shown in Fig. 1. Evaluation of the titration endpoint is handled by proprietary data analysis algorithms in the instrument software. 
 

FIG. 1. As titrant is added, an exothermic reaction is measured; i.e., the temperature in the titration vessel increases. After reaching the neutralization, or endpoint, excess titrant endothermically reacts with the thermometric indicator present in the solvent, resulting in an abrupt temperature decrease.
FIG. 1. As titrant is added, an exothermic reaction is measured; i.e., the temperature in the titration vessel increases. After reaching the neutralization, or endpoint, excess titrant endothermically reacts with the thermometric indicator present in the solvent, resulting in an abrupt temperature decrease.


The measuring response time of the thermistor is less than 0.003 sec and is much faster than that of a pH glass membrane. This means that thermometric titration by ASTM D8045 can be carried out much faster than titration by potentiometric methods, which use pH indication without sacrificing precision or accuracy.

The thermometric sensor also allows the use of nonpolar solvents, such as xylene, which improves the solubility of many oils, including crude. Thermometric titration does not require an insulated reaction chamber, because a relative temperature change is monitored to indicate completion of the reaction.

Sample preparation

The heterogeneous nature of crude oil can affect determinations, particularly when measuring relatively small sample sizes of 3 g–5 g. To improve the precision of the test protocol, it is necessary to homogenize the crude before analysis using a shear mixer. Studies by the work group have shown that this improves the precision of the new test method.

To optimize the solvent system in ASTM D8045, a solvent study was conducted. It was found that a mixture of xylene and 2-propanol (also called isopropyl alcohol, or IPA) in the ratio of 75:25 by volume worked best to dissolve the variety of crudes and refinery fractions. The xylene–2-propanol titration solvent is efficient enough that only 30 ml–40 ml of solvent is required, compared to 120 ml for ASTM D664. The reduction in total solvent volume and waste disposal saves substantial operating costs.

Crudes and refinery fractions that are liquid at room temperature are weighed directly into a beaker; 30 ml of titration solvent containing the thermometric indicator is added to dissolve the sample, which is then titrated with 0.1 molar potassium hydroxide in 2-propanol. Samples that are not liquid at room temperature, such as asphalt and high-paraffin-content fractions, require sample preparation.

Challenging samples with high paraffin content

The analyst may encounter crude oils with high paraffinic content, referred to as “waxy crudes.” These samples can be challenging because the paraffins are often solid at room temperature. Samples with high paraffinic content should be fluidized and homogenized by heating to 80°C, so that a representative aliquot is obtained and analyzed.

The warm sample is then weighed in the titration beaker, and 10 ml of solvent (toluene or xylene) is added. The majority of crudes analyzed, including bitumen samples, did not require this first dissolution step. Approximately 30 ml of the xylene–2-propanol titration solvent is added, and the sample aliquot is reheated to 65°C to ensure the dissolution of the paraffin content. The warm sample may be analyzed immediately, without adversely affecting endpoint resolution, further supporting the method ruggedness of D8045.

Recommended sample weights

Crudes and distillation fractions with an expected TAN of less than 1 mg KOH/g should be analyzed using a sample mass of 10 g–20 g. If the TAN is greater than 1 mg KOH/g, the analyst should use 5 g of sample for the measurement. The amount used can be adjusted to accommodate for solubility limitations. For unknowns, it is advised to start with 5 g and adjust the sample size as needed for subsequent measurements. The volume of titrant consumed must be at least 0.15 ml. A titrant volume smaller than 0.15 ml indicates that a larger sample is required. Conversely, a titrant volume greater than 5 ml suggests that a smaller sample is needed. Recommended sample weights, according to the expected value of the TAN, are presented in Table 1.
 

Blank determination

It is important to determine a blank periodically. This should consume less than 0.1 ml of titrant, particularly when measuring samples with a TAN of less than 1 mg KOH/g. To ensure that the blank value is less than 0.1 ml, only American Chemical Society (ACS) reagent-grade solvents should be used.

To determine the blank, a stable sample with a known TAN is measured three or more times, using a different sample mass each time. The largest sample size must not use a titrant volume greater than the volume of the burette. The example in Fig. 2 shows a blank calculation for a crude oil sample with a TAN of approximately 0.9 mg KOH/g.
 

FIG. 2. The blank value is determined from three or more determinations of the same sample, each of which is conducted using a different sample mass. The titrant volume required in these determinations is plotted against the respective sample mass. After a linear fit is applied, the blank value, equal to the titrant volume when the sample mass is 0 g, is extrapolated.
FIG. 2. The blank value is determined from three or more determinations of the same sample, each of which is conducted using a different sample mass. The titrant volume required in these determinations is plotted against the respective sample mass. After a linear fit is applied, the blank value, equal to the titrant volume when the sample mass is 0 g, is extrapolated.

 
In a plot of the titrant volume consumed until the endpoint against the sample mass, the blank value is equal to the value of the titrant volume y when the sample value x is set to zero (Fig. 2). In this particular example, it equals 0.039 ml. Titration software can be configured to fit the data and calculate the slope automatically.

Results: Correlation of thermometric and potentiometric methods

A variety of crude types and refinery fractions have been analyzed using the new thermometric ASTM D8045 titration standard. A study comparing this method to the ASTM D664 potentiometric method shows good correlation (Table 2).
 

 

 
In a three-laboratory study, 89 samples were analyzed using potentiometric and thermometric methods to compare the method results. The results showed that the new thermometric method described in ASTM D8045 produces equivalent results to the method in ASTM D664, as shown in Fig. 3.
 

FIG. 3. Correlation of the results of the thermometric TAN determination and the potentiometric TAN determination, according to ASTM D664.
FIG. 3. Correlation of the results of the thermometric TAN determination and the potentiometric TAN determination, according to ASTM D664.

Repeatability

The TAN repeatability of the thermometric method was studied for low-TAN samples in a single laboratory. A crude oil, a mineral oil and a refinery fraction were analyzed. The results are shown in Table 5. ASTM D8045 demonstrates excellent method precision for low TAN values.
 

Precision

The single-laboratory precision, as well as the precision between multiple laboratories, have been studied in the development of the ASTM D8045 thermometric acid number standard. This was done in a 10-laboratory study of 12 crudes and refinery fractions.

Both the single-laboratory precision, or repeatability, and the precision between multiple laboratories, or reproducibility, proved to be much better than that of method D664 when measuring crudes and refinery fractions. These improvements are attributed to an improved solvent system that makes the sample fully accessible for reaction to the titrant, as well as the use of a precise, enthalpy-detecting sensor that is unaffected by difficult samples or harsh solvents.

Takeaway

The new thermometric standard, ASTM D8045, offers the highest accuracy for the analysis of the total acid content in crudes and refinery fractions. By solving sample solubility and acidity accuracy issues, D8045 offers increased precision between buyers and sellers of petroleum products, and is a recommended standard to add to these agreements. By using 75% less solvent and reducing the analysis time, the new solvent system also considerably reduces the cost of testing. Table 6 provides an overview of D8045’s most important improvements for the analyst compared to ASTM D664.
 

 
From crude feedstock to refinery fractions, extensive testing and method development using proprietary thermometric titrators for TAN by D8045 prove to be simple and precise. With improved measurement, refiners can better adjust their plant operation to control and mitigate corrosion risk from naphthenic acid, while ensuring fair trade and commerce throughout the industry. HP

LITERATURE CITED

  1. Derungs, W. A., “Naphthenic acid corrosion—An old enemy of the petroleum industry,” Corr., 1956, Vol. 12.
  2. Turnbull, A., E. Slavcheva and B. Shone, “Factors controlling naphthenic acid corrosion,” Corr., Vol. 54, Iss. 11, 1998.
  3. Slavcheva, E., B. Shone and A. Turnbull, “Review of naphthenic acid corrosion in oil refining,” Br. Corr. J., 1999, Vol. 34, Iss. 2.
  4. Babaian-Kibala, E., H. L. Craig, G. L. Rusk, R. C. Quinter and M. A. Summers, “Naphthenic acid corrosion in refinery settings,” Mater. Perform., 1993.
  5. Bota, G. M., D. Qu, S. Nesic and H. A. Wolf, “Naphthenic acid corrosion of mild steel in the presence of sulfide scales formed in crude oil fractions at high temperature,” Paper No. 1035377, NACE 2010, San Antonio, Texas, March 14–18, 2010.
  6. Gutzeit, J., “Naphthenic acid corrosion in oil refineries,” Mater. Perform., Vol. 16, No. 10, October 1977.
  7. Murray, D., “TAN thermometric method evaluation,” Canadian Crude Quality Technical Association, April 2014.

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