Improve understanding of corrosion inhibitor technology for processing high-acid crudes
For corrosion risk assessment and control, ample published research exists on the inherent corrosivity of combinations of naphthenic acid and sulfur in refining systems, but not on the chemistry and mechanism of corrosion inhibitors. This work offers refinery engineers insight into the construction of corrosion inhibitor molecules, as well as how differences in molecules impact the performance of the inhibitor and the risk of fouling in crude units and hydroprocessing units.
The use of high-temperature corrosion inhibitors (HTCIs) for processing high-acid crudes began more than 30 yr ago, driven by economics that persist today. The economic justifications for using HTCIs are the difference between crude cost savings from the substitution of lower-cost, high-acid crudes into the blend, and the operating and capital costs of the chemical program and any other incremental costs and risks identified in the management of change (MOC) process. Incremental costs and risks include not only the impact of overall corrosion, but also potentially on crude blending and dehydration, desalter and wastewater treatment, crude units and hydroprocessing units.
For corrosion risk assessment and control, ample published research exists on the inherent corrosivity of combinations of naphthenic acid and sulfur in refining systems, but not on the chemistry and mechanism of corrosion inhibitors.1,2 This work offers refinery engineers insight into the construction of corrosion inhibitor molecules, as well as how differences in molecules impact the performance of the inhibitor and the risk of fouling in crude units and hydroprocessing units. Increased understanding of these concepts will improve corrosion inhibitor selection and performance, as part of a crude flexibility strategy to process crudes that are discounted due to naphthenic acid content.
Naphthenic acid corrosion
Naphthenic acid reacts with iron metal to form an oil-soluble iron naphthenate in the temperature range between 392°F and 752°F (200°C and 400°C), shown in Eq. 1:
2RCOOH + Fe0 → (RCOO)2Fe + 2H• (1)
Over the same temperature ranges (i.e., in similar locations), reactive sulfur compounds oxidize iron metal to form insoluble iron sulfide scales. The sulfidation mechanism involves reactive sulfur (a fraction of the total S), which is commonly expressed assuming the intermediate formation of hydrogen sulfide (H2S), so that sulfidation corrosion is represented by Eq. 2:
H2S + Fe0 → FeS +2H• (2)
Simultaneous sulfidation and naphthenic acid (SNAP) corrosion generally occurs in crude units and in hydroprocessing units upstream of the hydrogen injection point.
Iron sulfide scales formed in the sulfidation reaction are replete with cracks, fissures and spalls. The cracks in the scale form, due to the high ratio of the volume of sulfide corrosion scale formed relative to the volume of the corroded iron substrate.3 Although iron sulfide scales from carbon steel and chrome alloys provide some protection against naphthenic acid corrosion, many refineries find that this protection is inadequate to allow processing of significant levels of high-acid crudes without the use of corrosion inhibitors or upgrades in metallurgy.
Corrosion inhibitors work by reducing the porosity of the cracks and fissures of the iron sulfide scale. This reduces the amount of naphthenic acid that reaches the base metal surface; therefore, the rate of corrosion is reduced. Phosphorus, which changes the porosity of the iron sulfide scale, is the critical chemical reactant in many inhibitors. When introduced into the system in the proper form, it creates an iron polyphosphate that produces chemical cross-links with grains of iron sulfide in the scale to reduce cracks and fissures.
Phosphorus is used to improve corrosion resistance in coatings, lubricants, drilling fluids, oil fields and water systems. The forms of phosphorus and phosphorus delivery systems are different, depending on the application. For refining HTCIs, the phosphorus delivery system is a class of chemicals called phosphate esters. Important differences in the construction of refining HTCIs impact the inhibitor’s effectiveness of reducing corrosion without causing fouling. An explanation of these differences in molecular construction, and their impact on the mechanism of corrosion inhibition, are detailed here.
Corrosion inhibitor chemistry and phosphate esters description
For more than 20 yr, suppliers have been offering various types of phosphate esters that have proven to reduce SNAP corrosion. Phosphate esters are a group of compounds where one or more hydrogen atoms of phosphoric acid have been replaced with a hydrocarbon entity (“R”). FIG. 1 shows the similarity between phosphoric acid and phosphate esters.
FIG. 1. Comparison of phosphoric acid and phosphate esters.
Phosphate esters and thiophosphate esters (sulfur in molecule) are produced by reacting an alcohol with phosphorous pentoxide or phosphorous pentasulfide. Phosphorus pentoxide is the anhydride of phosphoric acid, and is produced in the thermal route to the production of phosphoric acid. The reaction with phosphorus pentoxide is shown in FIG. 2, reaction 3. This phosphorylation of an alcohol creates a mixture of mono-esters and di-esters, collectively called partial esters. Partial esters have the P-OH group present in their structure, and are as acidic as phosphoric acid; they were introduced more than 30 yr ago and are commonly present in HTCIs in commercial use. Some are amine neutralized to reduce the acidity of the product in handling. At application temperatures, the amines volatilize, leaving the acidic phosphate ester in the system.
FIG. 2. The phosphorylation of an alcohol creates a mixture of mono-esters and di-esters, collectively called partial esters.
Recently, the option to use a tri-ester for corrosion control has become available. These tri-esters are created by reacting partial esters with ethylene oxide, shown in FIG. 3, reaction 4. Tri-esters are non-acidic.
FIG. 3. Tri-esters are made by reacting partial esters with ethylene oxide, enabling their use for corrosion control.
Mechanism of corrosion inhibition
Synthesis of the HTCI molecule results in oil-soluble, phosphorous-based surfactants. The “R” groups supplied by the alcohol provide the oil solubility to transport the oil-soluble phosphorus to column internals and pipe walls. The phosphate ester molecule diffuses into the scale, and the O-R and O-H bonds chemically react with ferrous and ferric ions of iron that are present in the existing iron sulfide scale to form a cross-linked iron polyphosphate (FIG. 4). The iron polyphosphate incorporated into the scale renders the scales less porous and more resistant to flow stress.
FIG. 4. A simplified model of HTCI inhibitor reaction.
The chemical concentration required to create the iron polyphosphate scale is higher than that required to sustain it. If no cross-linking exists when the chemistry is first introduced into the system, it takes time and concentration for the phosphorus to repair existing cracks and fissures. This explains why the HTCI implementation plan generally includes a passivation step that uses higher-than-maintenance chemical dosage.
When the passivation step is finished, the corrosion rate is lower, although it continues. The continuing reaction with the base metal creates voluminous scale at the surface, which creates instability in the surface scale. The maintenance dosage works to repair the cracks created in this process.
To minimize the risk of phosphorus fouling,4,5 refiners desire to control corrosion with the minimum amount of phosphorus added. The ideal phosphate ester molecule is highly reactive with ferrous and ferric ions of iron. It is clean in use, infusing phosphorus cross-links into iron sulfide scale, rather than clumping into particulate iron phosphate grains that may get physically trapped in the scale and make the scale more porous to naphthenic acid diffusion to the base metal.
Field experience and lab measurements demonstrate that partial esters decompose to insoluble phosphorus containing particulates at temperatures common to refining. The insoluble precipitate cannot contribute to the inhibition reactions, and may do harm by increasing scale porosity. In contrast, tri-esters are known to be more thermally stable and clean in use.
The amount of soluble phosphorus in the bulk fluid that is necessary to control corrosion in refining systems depends upon the baseline corrosion rate without inhibitor and the desired corrosion rate. The baseline corrosion rate is a function of metallurgy, total acid number (TAN), reactive sulfur, temperature and shear stress. The soluble phosphorus concentration required to meet the objective increases as the gap between baseline and target corrosion rate increases.
Despite the large number of variables involved, field experience shows that, for a properly passivated system, the level of soluble phosphate ester required to maintain the protective scale is typically in a relatively narrow range—0.08 ppm to 0.25 ppm as “P”. This establishes the lower bound of the phosphorus dosage requirement. The dosage of the product required is the sum of the soluble phosphorus needed for protection, plus the quantity lost in insoluble phosphorus precipitation.
Estimating quantity of insoluble phosphorus precipitate
A simple thermal test can be used to illustrate differences in the thermal stability among commercially available HTCIs (FIG. 5). In this test, each product was diluted to the same concentration of P (20 ppm) in neutral white oil containing naphthenic acid. The solutions were heated with stirring to 554°F (290°C) for two hours in a glass, round-bottom flask. Samples were taken from the flask every 5 min. at first, and then at increased time intervals as the test proceeded. Soluble phosphorus was measured over time. In only 5 min., Product C, a commercially used partial ester, showed a dramatic reduction in soluble phosphorus that continued to drop to less than 25% of the phosphorus remaining in solution after 30 min. Product B, another commercially used partial ester, had 50% of the product solubility remaining after 30 min. Product A, a commercially used tri-ester, had 95% of the product solubility remaining after 30 min., and 90% solubility remaining after 120 min. FIG. 6 shows the physical appearance of the precipitate.
FIG. 5. Results of a thermal stability test.
FIG. 6. Flasks from a thermal stability test.
Why are partial esters inherently thermally unstable compared to tri-esters? Research has shown that the ionic O-H bond is susceptible to heat, while the O-R bond is more thermally stable.6 In addition, the thermal stability of the alcohol used to produce the ester also is important. The R group in Product A (tri-ester) is a thermally stable polyisobutylene material with a molecular weight of approximately 1,000.
Polyisobutylene is commonly used as a surfactant in engine oil formulations, and is chosen for its thermal stability. The R group in the partial esters (Products B, C) are typically linear hydrocarbon chains with a molecular weight of 20 to 30, and are less thermally stable than the branched polyisobutylene.
Fouling experience with partial ester HTCIs
A 400-Mbpd refinery in Asia-Pacific using a partial ester HTCI experienced increased pressure drop across the kerosine and light gasoil (LGO) section of the crude column. FIG. 7 and TABLE 1 illustrate the deposit analyses from the inspection.
FIG. 7. Phosphorus fouling in a crude column.
Both sections had high ash content in the deposit, with significant amounts of iron and phosphorus. Some of the deposit was soluble in demineralized water, and reduced the pH of the demineralized water to less than 3. The acid was identified to be phosphoric acid, a decomposition product of partial esters.
Comparison of tri-esters with partial esters for corrosion control and fouling risk
Do commercially available HTCIs inhibit corrosion if fed at a high enough dosage? The answer is unequivocally, “Yes,” for tri-esters and partial esters.7,8,9 This has been confirmed by field experience and lab tests. How is dosage measured, and what dosage is high enough?
Dosage is measured in two important ways: by product and by level of phosphate ester (ppm as P). The corrosion engineer uses the product dosage to properly administer the program, and for chemical cost budgeting. Hydroprocessing engineers want to know the total level of phosphorus added in ppm as P—the quantity of “R” groups added is of no concern to them. However, the level of phosphorus is of concern; not all of the phosphorus added is consumed as protective scale. Material not consumed as protective scale may remain in the feed to downstream hydroprocessing units. Measurements of the level of phosphorus in the outlet of the reactor in systems using HTCIs are below detection limits. The balance between inlet and outlet phosphorus, if any, will deposit in either the guard bed or reactor. Improved corrosion control reduces iron loading on downstream hydroprocessing units and extends equipment life.
What dosage is high enough for corrosion control? It is the level of total phosphorus that accounts for loss from thermal decomposition, such that the remaining soluble phosphorus is enough to meet the demand for corrosion inhibitor. For a thermally stable tri-ester, the total phosphorus added is very close to the soluble phosphorus required. For the thermally unstable partial ester, the total phosphorus added is four to six times higher than the soluble phosphorus required.
Lab tests demonstrate significant differences in corrosion inhibition between partial esters and tri-esters. TABLE 2 illustrates a comparison of Product A (tri-ester with polyisobutylene R groups) vs. Product C (partial ester with “R” groups of molecular weight < 30) at P levels of Product C of four times the P levels of Product A. Results show that Product A outperforms Product C at 75% less phosphorus.
HTCIs are phosphate ester surfactants with varying design of R groups and degrees of esterification. They work by reacting soluble phosphate esters with the existing scale to make it less porous and more resistant to shear stress. Historically, the choice of HTCI available to refiners has been from partial esters made with low-molecular-weight R groups. Partial esters are acidic, and the acid group (O-H) is inherently unstable. The instability degrades the efficiency of the corrosion inhibitor.
The thermal stability limitation of partial esters can be overcome by adding enough additional product, such that sufficient soluble phosphorus exists to strengthen iron sulfide scale and inhibit corrosion. The increased risk of fouling is one of the negative consequences of adding more phosphorus. The particulate phosphorus does not participate in the crosslinking reactions that strengthen the corrosion inhibiting scale. Instead, acid phosphate particulates can be formed that have the potential to settle in micro-fractures of the scale and negatively impact corrosion inhibition by physically limiting crosslinking. Alternatively, acid phosphate particulates may deposit on the surface of the scale and induce fouling in equipment in contact with the inhibitor.
New HTCI options available are a combination of high-molecular-weight, thermally stable polyisobutylene R groups and esterification to a non-acidic tri-ester. This tri-ester class of HTCI minimizes phosphorous waste from thermal instability, and provides corrosion protection with up to 80% less phosphorus. The lower phosphorus levels required are more acceptable to hydrotreating experts, especially when compared to the cost reduction available with high-acid crudes. Improved corrosion control reduces iron loading on downstream hydroprocessing units and extends equipment life. The result is a set of new options for the refinery for increased crude flexibility with existing assets, and improved understanding of corrosion inhibitors. HP
- Johnson, D., G. R. McAteer and H. Zuk, “Mitigating corrosion from naphthenic acid streams,” PTQ, pp. 79–85, 1Q 2003.
- Dwivedy, S. and R. Navarrete, “Treatment program overcomes high TAN problems,” PTQ, 4Q 2015.
- “Prediction tools for sulfidic corrosion, overview of sulfidic corrosion in petroleum refining,” NACE Intl. Task Group 176, NACE Intl., February 2004.
- Nizio, K. D., “Profiling alkyl phosphates in petroleum samples by comprehensive two-dimensional gas chromatography with nitrogen-phosphorus detection,” Department of Chemistry, University of Alberta, Alberta, Canada, 2014.
- Fink, J. K., Guide to the practical use of chemicals in refineries and pipelines, Gulf Professional Publishing, May 9, 2016.
- Higgins, C. E. and W. H. Baldwin, “The pyrolysis of n-butyl phosphate esters and salts,” The Journal of Organic Chemistry, Iss. 9, Vol. 30, 1965.
- Ondyak, J., M. Subramaniyam, J. Noland, D. Comer and P. Shah, “Changing perspectives on TAN management in refining,” NACE Corrosion 2016, No. 7,491.
- Srinivasan, V., M. Subramaniyam and P. Shah, “Processing strategies for high-metal and high-acid crudes, PTQ, 4Q 2013.
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