NAPTHENIC ACID CORROSION REVIEW.pdf

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Naphthenic Acid Corrosion Review

Introduction Manifestation of Naphthenic Acid Corrosion Parameters Affecting Naphthenic Acid Corrosion

Naphthenic Acid Chemistry Sulfur Compounds Temperature Velocity Materials of Construction

Mitigation Methods Laboratory Testing Conclusions References and Further Reading

Introduction

High temperature crude corrosivity of distillation units is a major concern to the refining industry. The presence of naphthenic acid and sulfur compounds considerably increases corrosion in the high temperature parts of the distillation units and equipment failures have become a critical safety and reliability issue. The difference in process conditions, materials of construction and blend processed in each refinery and especially the frequent variation in crude diet increases the problem of correlating corrosion of a unit to a certain type of crude oil. In addition, a large number of interdependent parameters influences the high temperature crude corrosion process.

Manifestation of Naphthenic Acid Corrosion

Isolated, deep pits in partially filmed areas and/or impingement attack in essentially film free areas is typical of naphthenic acid corrosion (NAC). Damage is in the form of unexpected high corrosion rates on alloys that would normally be expected to resist sulfidic corrosion. In many cases, even very highly alloyed materials (i.e., 12 Cr, AISI 316 and 317) have been found to exhibit sensitivity to corrosion under these conditions. NAC is differentiated from sulfidic corrosion by the nature of the corrosion (pitting and impingement) and by its severe attack at high velocities in crude distillation units. Crude feedstock heaters, furnaces, transfer lines, feed and reflux sections of columns, atmospheric and vacuum columns, heat exchangers, condensers are among the type of equipment subject to this type of corrosion.

Parameters Affecting Naphthenic Acid Corrosion

The chemistry, content, boiling point distribution, and decomposition temperature of naphthenic acid and sulfur compounds have a direct effect on the high temperature corrosion of the distillation unit. Process conditions such as velocity, degree of vaporization and temperature, and alloy composition are also important factors affecting the corrosion process.

Naphthenic Acid Chemistry

Naphthenic acid is a generic name used for all the organic acids present in crude oils. Most of these acids are believed to have the chemical formula R(CH2)nCOOH where R is a cyclopentane ring and n is typically greater than 12. However, a multitude of other acidic organic compounds are also present and not all of them have been analyzed to date. Crude oils from California, Venezuela, North Sea, Western Africa, India, China, and Russia have typically a high naphthenic acid content.

There are several methods for the determination of naphthenic acid content. Unfortunately, these methods lead to

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different results.

1. The ASTM procedures for Total Acid Number (TAN) also called neut number were not developed for crude oils. There were used for determining the oxidation of petroleum products and lubricants. ASTM D974 is a colorimetric titration method and has a reproducibility of 15%. ASTM D664 is a potentiometric titration method with reproducibility of 20 to 44% depending on the end point (buffer or inflection), type of oil (used or fresh), and titration mode (automatic or manual). Inorganic acids, esters, phenolic compounds, sulfur compounds, lactones, resins, salts, and additives such as inhibitors and detergents interfere with both methods. In addition, these ASTM methods do not differentiate between naphthenic acids, phenols, carbon dioxide, hydrogen sulfide, mercaptans, and other acidic compounds present in the oil.

2. In the UOP procedures, sulfur compounds are removed before analysis of acid number. UOP 565 is a by potentiometric method and UOP 587 is a colorimetric method.

3. In the chromatographic method or Mobil method naphthenic acid are expressed by weight percent. The acids are extracted by liquid chromatography and then analyzed by IR spectroscopy. Unfortunately, the instrument is calibrated with standard naphthenic acid, which might not have the same composition and molecular weight as the sample. Thus, the weight percent can be used for comparison purpose only.

4. Another variation of the chromatographic method is the Naphthenic Acid Number (NAN) or Naphthenic Acid Titration (NAT) whereby the sample is extracted by chromatography and then titrated per ASTM D664.

The Fast Atom Bombardment Mass Spectroscopy (FAB-MS) analysis determines the molecular weight distribution of the naphthenic acid extracted from the oil. This method is mainly used to fingerprint crude oils from around the world. Research is still underway to apply this technique to corrosivity prediction.

The naphthenic acids are most active at their boiling point and the most severe corrosion generally occurs on condensation. Crude oils with a TAN higher than 0.5 and cuts with a TAN higher than 1.5 are considered to be potentially corrosive between the temperature of 450 to 750F. However, there are many cases including high velocity, high TAN and others where these rules of thumb break down and correlating the TAN of specific cut to their corrosivity is still far from being reached.

Sulfur Compounds

Other than carbon and hydrogen, sulfur is the most abundant element in petroleum. It may be present as elemental sulfur, hydrogen sulfide, mercaptans, sulfides, and polysulfides. The total sulfur content is generally analyzed with ASTM D4294 method using X-ray fluorescence. Halides and heavy metals interfere with this method.

Sulfur at a level of 0.2% and above is known to be corrosive to carbon and low alloy steels at temperatures from 230 (450 ? F) to 455 ? C (850 ? F). When sulfur is the only contaminant, McConomy curves, with the help of correction factors, are used to predict the relative corrosivity of crude oils and their various fractions as well as the effect of operational changes on corrosion rates already experienced in the field. Sulfur content of the cuts and more advanced analysis of specific sulfur compounds such as H2S, mercaptans, sulfides, polysulfides when correlated to field data

appears to help predict crude corrosivity much better. Hydrogen sulfide evolution tests were also used to predict crude corrosivity. As early as 1953, it was found that the H2S evolved at 850F correlated very well with experienced corrosion

of 21 out of 22 oils tested. Piehl’s work also showed that there was a good correlation of corrosion with H2S evolution. A

standard procedure for the hydrogen sulfide evolution with temperature is not currently available.

At high temperature, especially in furnaces and transfer lines, the presence of naphthenic acids may increase the severity of sulfidic corrosion. The presence of these organic acids may disrupt the sulfide film thereby promoting sulfidic corrosion on alloys that would normally be expected to resist this form of attack (i.e., 12 Cr and higher alloys). In some cases, such as in side cut piping, the sulfide film produced by H2S are believed to offer some degree of protection from naphthenic acid corrosion.

Temperature

In general, corrosion rate of all alloys in the distillation units increases with increase in temperature. Naphthenic acid



corrosion occurs primarily in high velocity areas of crude distillation units in the 220 to 400 ? C (430 to 750 temperature range. No corrosion damage is usually found at temperatures above 400 ? C (750 ? F), most probably because of the decomposition of naphthenic acids or protection from the coke formed at the metal surface.

Velocity

Velocity and more importantly wall shear stress is a main parameter affecting NAC. Fluid flow velocity lacks predictive capabilities. Data related to fluid flow parameters such as wall shear stress and Reynold’s Number is more accurate because the density and viscosity of liquid and vapor in the pipe , the degree of vaporization in the pipe and the pipe diameter are also taken into account.

To estimate wall shear stress, it is necessary to know the density and viscosity of the liquid and the vapor, the degree of vaporization and the pipe diameter. The chart of Diameters versus Roughness and chart of Friction Factors (Moody Diagram) are also needed. First, the Reynold’s Number for field flow conditions in a pipe is calculated by the following equation:

Re = D ? V / ??

where Re = Reynold’s Number

D = diameter of pipe (m) ?????????????????????? = density of fluid (Kg/m3) V = velocity of fluid (m/s) ????????????????????? = dynamic viscosity (Kg/m.s, 1 Poise = 0.1 Kg/m.s)

With the Reynolds number known, the Relative roughness (e /D) is obtained from the chart of Diameters versus Relative Roughness and the Friction factor (f) is then obtained from the Moody Diagram. Finally, the Shear Stress (?) is calculated by the following equation:

? = f ? V2 / ?

To use plant corrosion data of a specific crude or blend as a way to predict its corrosivity for another plant: (1) Calculate shear stress for plant with known corrosion data, (2) calculate shear stress for plant which is planning to run the specific crude or blend and (3) compare both shear stress. Corrosion rates are directly proportional to shear stress. Typically, the higher the acid content, the greater the sensitivity to velocity. When combined with high temperature and high velocity, even very low levels of naphthenic acid may result in very high corrosion rates.

Materials of Construction

Above 288 ? C (550 ? F), and very low naphthenic acid content, 5 Cr or 12 Cr cladding is recommended for crudes over 1% sulfur when no operating experience is available. When hydrogen sulfide is evolved, an alloy containing a minimum of 9% chromium is preferred. In contrast to high-temperature sulfidic corrosion, low-alloy steels containing up to 12% Cr do not seem to provide benefits over carbon steel in naphthenic acid service. 316 SS (with 2.5% Mo minimum) or better 317 SS with a higher Mo content (3.5% minimum) cladding of vacuum column is recommended when TAN is above 0.5 mg KOH/g and in atmospheric column when the TAN is above 2.0 mg KOH/g.

Mitigation Methods

Mitigation of naphthenic acid corrosion includes blending, inhibition, materials upgrading and process control.

Blending may be used to reduce the naphthenic acid content of the feed by diluting a high TAN crude with a low TAN one, thus reducing corrosion to an acceptable level. Blending of heavy and light crudes change shear stress parameters and might also help reduce corrosion. Blending is also used to increase the level of sulfur content in the feed and inhibit to some degree naphthenic acid corrosion.

Injection of corrosion inhibitors may provide protection for specific fractions that are known to be particularly severe. Monitoring need to be adequate in this case to check on the effectiveness of the treatment.



Process control changes may provide adequate corrosion control if there is possibility to reduce charge rate and temperature.

For long term reliability, upgrading the construction materials to a higher chrome and/or molybdenum alloy is the best solution.

Laboratory Testing

Several parameters need to be defined in planning a laboratory crude corrosion tests: (1) oil fraction, (2) temperature, (3) wall shear stress (velocity), (4) alloy composition, (5) exposure time and (6) testing procedure. Laboratory corrosion tests still need to be correlated to refinery experience.

Process Simulation

Furnace Tubes and Transfer Lines - In furnace tubes and transfer lines, vaporization and fluid velocity are very high. The high temperature conditions appears to activate even small amounts of naphthenic acid in oil increasing corrosion significantly. Thus, at furnace tubes and transfer lines conditions, the influence of temperature, velocity and degree of vaporization is very large. Process conditions such as load and steam rate and especially turbulence affect corrosivity. The corrosion mechanism at the furnace tubes, transfer lines, areas of high turbulence such as thermowells and pumps, is most likely an accelerated corrosion due to the velocity and the two-phase flow. Simulation of these conditions in the laboratory requires conditions of high degree of vaporization and relatively low wall shear stress . A rotating electrode, with specimens in the vapor phase easily simulate the high velocity conditions found in the field. A flow loop with jet impingement simulates only a liquid flow and is not adequate in this case.

Vacuum Column - In the vacuum column, preferential vaporization and condensation of naphthenic acids increase TAN of condensates. There is very little effect of velocity. Corrosion takes only place in the liquid phase. It is mainly a condensate corrosion and is directly related to content, molecular weight and boiling point of the naphthenic acid . Corrosion is typically severe at the condensing point corresponding to high TAN and temperature. Simulating vacuum tower corrosion requires the specimens to be exposed in the condensing phase and not in the vapor or liquid phase. This requires apparatus common to corrosion studies in the chemical industry. An autoclave and a flow loop jet impingement are not adequate for testing corrosion in this case.

Side Cut Piping - In side-cut piping, conditions of low vaporization and medium fluid velocity exist. Some studies showed a possible inhibition of NAC by sulfur compounds. In these conditions, an increase in velocity increases corrosion rates up to the point where impingement starts and corrosion is accelerated dramatically. The corrosion process is dependent on flow, temperature, materials of construction and naphthenic acid and H2S content. A stirred autoclave or a flow loop with jet impingement are typically used to simulate these conditions.

Testing Procedure

There are several methods for testing crude oils: (1) continuous purge with nitrogen where corrosion rates are typically very low since all evolved H2S is removed continuously by the continuous nitrogen purging, (2) sealing of autoclave

where the evolved H2S and light components increase the pressure of the system, thus increasing corrosion rates, and (3) setting the pressure level arbitrarily to a certain point using a pressure relief valve and condenser. Several other testing procedure details such as volume ratio of liquid to vapor, deaeration of autoclave, stirring of oil during test, cleaning of specimens after test are also critical to the validity of the test results and need to be defined early in the program.

Conclusions

High temperature crude corrosion is a complex problem. There are at least three corrosion mechanisms corresponding to: (1) furnace tubes and transfer lines where corrosion is dependent on velocity and vaporization and is accelerated by naphthenic acid, (2) vacuum column where corrosion occurs at condensing temperature, is independent of velocity and increases with naphthenic acid concentration, and (3) side cut piping where corrosion is dependent on naphthenic acid content and is inhibited somewhat by sulfur compounds.

The industry still relies heavily on previous experience and readily available data on TAN and sulfur of cuts when processing opportunity crudes. Despite their shortcoming, rules of thumb are still used mainly because of lack of resources and time of the plant



corrosion engineer.

The uniqueness in process conditions, materials of construction and blend processed in each refinery and especially the frequent variation in crude or blend processed does still not allow an accurate correlation of plant experience to chemical analysis and laboratory corrosion tests. In addition to corrosion data, there is a need for better monitoring and recording of the process conditions (temperature, velocity, and vaporization) and the analytical data (TAN of cuts, type of acid and sulfur compounds present).

References and Further Reading

Derungs, W.A., "Naphthenic Acid Corrosion – An Old Enemy Of The Petroleum Industry", Corrosion, 12(2), 41(1956).Gutzeit, J., "Naphthenic Acid Corrosion In Oil Refineries", Materials Performance, 33(10), 24(1977). Piehl, R.L., ""Naphthenic Acid Corrosion in Crude Distillation Units", Materials Performance, 44(1), 37(1988). Craig, H.L., "Naphthenic Acid Corrosion in the Refinery", CORROSION/95, Paper # 333, NACE, Houston, Texas, 1995.Craig, H.L., "Temperature and Velocity Effects in Naphthenic Acid Corrosion", CORROSION/96, Paper # 603, NACE, Houston, Texas, 1996. Heller, J.J., R.D. Merick and E.B. Marquand, "Corrosion of Refinery Equipment by Naphthenic Acid", NACE Publication 8B163, Materials Protection , 2(9), 44(1963). REFIN.COR Version 3.0, NACE International, Houston, Texas, 1996. ASTM Method D974, "Test Method for Acid and Base Number by Color-Indicating Titration", Annual Book of ASTM Standards, Volume 05.01. ASTM Method D664, "Test Method for Acid Number of Petroleum Products by Potentiometric Titration", Annual Book of ASTM Standards, Volume 05.01. UOP Method 565 -92, " Acid Number and Naphthenic Acids by Potentiometric Titration", UOP, Des Plaines, Illinois, 1992.UOP Method 587 -92, " Acid Number and Naphthenic Acids by colorimetric Titration", UOP, Des Plaines, Illinois, 1992.Morrison B.L., D. DeAngelis, L. Bonnette and S. Wood, "The determination of Naphthenic Acids in Crude Oil", PittCon/92, New Orleans, Louisiana, 1992. "Refining Acid Crude", The CAPTAIN Report, Texaco Brochure, 1996. Cataldi, H.A., R.J. Askevold and A.E. Harnsberger, "Estimating the Corrosivity of Crude Oils", Petroleum Refiner(1953). Slater, J.E, W.E. Berry, B. Paris and W.K. Boyd, "High Temperature Crude Oil Corrosivity Studies", API Publication No. 943, September 1974. Port, G.R., Proceeding API, Division Refining, 41 (III), 98 (1961). Mottram, R.A. and J.T. Hathaway, "Some Experience in the Corrosion of a Crude Oil Distillation Unit Operating with Low Sulfur North African Crudes", CORROSION/71, Paper # 39, NACE, Houston, Texas, 1971. Slavcheva, E., B. Shone and A. Turnbull, "Factors Controlling Naphthenic Acid Corrosion", CORROSION/98, Paper # 98579, NACE, Houston, Texas, 1998. Blanco, E.F. and B. Hopkinson, "Experience with Naphthenic Acid Corrosion in Refinery Distillation Process Units", CORROSION/83, Paper # 99, NACE, Houston, Texas, 1983. Hau, J.L. and E.J. Mirabal, "Experience with Processing High Sulfur Naphthenic Acid Containing Heavy Crude Oils", 2Latin American Region Corrosion Congress, Paper # LA96037, NACE, Houston, Texas, 1996. Bardaz, E.A., "Proceeding 6th European Conference on Corrosion Inhibitors", Italy, 1985. Piehl, R.L., "Correlation of Corrosion in a Crude Distillation Unit with Chemistry of the Crudes" Corrosion, 16, 6(1960)."White R.A. and Ehmke E.F., "Materials Selection for Refineries and Associated Facilities", NACE, Houston, Texas, 1991.Babian-Kibala, E. et al.: "Naphthenic Acid Corrosion in a Refinery Setting", NACE Conference, CORROSION/93, Paper #631, 1993. Blanco, F. and Hopkinson, B.: "Experience with Naphthenic Acid corrosion in Refinery Distillation Process Units", NACE Conference, CORROSION 83, Paper #99, 1983. Scattergood, G.L. and Strong, R.C.: "Naphthenic Acid Corrosion, An Update of Control Methods", NACE Conference, CORROSION/87, Paper #197, 1987. Fau, Tseng -Pu, "Characterization of Naphthenic Acids in Petroleum by Fast Atom Bombardment Mass Spectrometry," Energy and Fuels, Vol. 5, No. 3, 1991: p. 371. Dzidic, I. et al., "Determination of Naphthenic Acids in California Crudes and Refinery Wastewaters by Fluoride Ion Chemical



Ionization Mass Spectrometry," Analytical Chemistry, Vol. 60, No. 13, July 1, 1988: p. 1318. Effird K.D. et al, "Experimental Correlation of Steel Corrosion in Pipe Flow Jet Impingement and Rotating Cylinder Laboratory Tests", Corrosion/93, Paper #81, NACE. Tebbal, S. et al., "Review of critical Factors Affecting Crude Corrosivity", NACE Conference, CORROSION/96, Paper # 607.Tebbal, S. et al., "Assessment of the Corrosivity of Crude Fractions from Varying Feedstock", NACE Conference, CORROSION/97, Paper # 498. Tebbal, S. et al., "Assessment of Crude Oil Corrosivity", NACE Conference, CORROSION/98, Paper # 578 Tebbal, S., "Critical Review of Naphthenic Acid Corrosion", NACE Conference, CORROSION/99, Paper # 380. Tebbal, S., "Predict Naphthenic Acid Corrosion", Hydrocarbon Engineering, April 2000, 4.

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