Naphthenic Acid Corrosion

Naphthenic Acid Corrosion Review Page

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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 presenc and sulfur compounds considerably increases corrosion in the high temperature parts of the distillation units an have become a critical safety and reliability issue. The difference in process conditions, materials of constructi processed in each refinery and especially the frequent variation in crude diet increases the problem of correlati to a certain type of crude oil. In addition, a large number of interdependent parameters influences the high te 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 o corrosion (NAC). Damage is in the form of unexpected high corrosion rates on alloys that would normally be exp corrosion. In many cases, even very h ighly alloyed materials (i.e., 12 Cr, AISI 316 and 317) have been found to e corrosion under these conditions. NAC is diff erentiated from sulfidic corrosion by the nature of the corrosion (pi impingement) and by its severe attack at high velocities in crude distillation units. Crude feedstock heaters, fur feed and reflux sections of columns, atmospheric and vacuum columns, heat exchangers, condensers are among 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 sul direct effect on the high temperature corrosion of the distillation unit. Process conditions such as velocity, and temperature, and alloy composition are also im portant 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 aci to have the chemical formula R(CH 2)nCOOH where R is a cyclopentane ring and n is typically greater tha a multitude of other acidic organic compounds are also present and not all of them have been analyzed oils from California, Venezuela, North Sea, Western Africa, India, China, and Russia have typically a acid content. There are several methods for the determination of naphthenic acid content. Unfortunately, these different results.


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1. The ASTM procedures for Total Acid Number (TAN) also called neut number were not developed There were used for determining the oxidation of petroleum products and lubricants. ASTM D974 i titration method and has a reproducibility of 15%. ASTM D664 is a potentiometric titratio reproducibility of 20 to 44% depending on the end point (buffer or inflection), type of oil (use titration mode (automatic or manual). Inorganic acids, esters, phenolic compounds, sulfur comp resins, salts, and additives such as inhibitors and detergents interfere with both methods. In ASTM methods do not differentiate between naphthenic acids, phenols, carbon dioxide, hy mercaptans, and other acidic compounds present in the oil. 2. In the UOP procedures, sulfur compounds are removed before analysis of acid number. UO potentiometric method and UOP 587 is a colorimetric method. 3. In the chromatographic method or Mobil method naphthenic acid are expressed by weight percent extracted by liquid chromatography and then analyzed by IR spectroscopy. Unfortunately, th calibrated with standard naphthenic acid, which might not have the same composition and mole 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 Titration (NAT) whereby the sample is extracted by chromatography and then titrated per ASTM D The Fast Atom Bombardment Mass Spectroscopy (FAB-MS) analysis determines the molecular weight dis naphthenic acid extracted from the oil. This method is mainly used to fingerprint crude oils from ar Research is still underway to apply th is technique to corrosivity prediction. The naphthenic acids are most active at their boiling point and the most severe corrosion gene condensation. Crude oils with a TAN higher than 0.5 and cuts with a TAN higher than 1.5 are co potentially corrosive between the temperature of 450 to 750F. However, there are many cases includin high TAN and others where these rules of thumb break down and correlating the TAN of specific cut to is still far from being reached. Sulfur Compounds Other than carbon and hydrogen, sulfur is the most abundant element in petroleum. It may be prese sulfur, hydrogen sulfide, mercaptans, sulfides, and polysulfides. The total sulfur content is generall 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 temperatu (450 ° F) to 455 ° C (850 ° F). When sulfur is the only contaminant, McConomy curves, with the hel factors, are used to predict the relative corrosivity of crude oils and their various fractions as well operational changes on corrosion rates already experienced in the field. Sulfur content of the cuts and analysis of specific sulfur compounds such as H 2S, mercaptans, sulfides, polysulfides when correlate appears to help predict crude corrosivity much better. Hydrogen sulfide evolution tests were also used corrosivity. As early as 1953, it was found that the H 2S evolved at 850F correlated very well with experi of 21 out of 22 oils tested. Piehl’s work also showed that there was a good correlation of corrosion with 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 m severity of sulfidic corrosion. The presence of these organic acids may disrupt the sulfide film thereby pr corrosion on alloys that would normally be expected to resist this form of attack (i.e., 12 Cr and higher cases, such as in side cut piping, the sulfide film produced by H 2S are believed to offer some degree of naphthenic acid corrosion. Temperature


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In general, corrosion rate of all alloys in the distillation units increases with increase in temperature. corrosion occurs primarily in high velocity areas of crude distillation units in the 220 to 400 ° C (4 temperature range. No corrosion damage is usually found at temperatures above 400 ° C (750 ° F), because of the decomposition of naphthenic acids or protection from the coke formed at the metal surfa Velocity Velocity and more importantly wall shear stress is a main parameter affecting NAC. Fluid flow velocity capabilities. Data related to fluid flow parameters such as wall shear stress and Reynold’s Number is because the density and viscosity of liquid and vapor in the pipe , the degree of vaporization in the pi 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 vapo vaporization and the pipe diameter. The chart of Diameters versus Roughness and chart of Friction Diagram) are also needed. First, the Reynold’s Number for field flow conditions in a pipe is calculated equation: Re = D

V/

where Re = Reynold’s Number D = diameter of pipe (m) ρ = density of fluid (Kg/m3) V = velocity of fluid (m/s) µ = 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 Roughness and the Friction factor (f ) is then obtained from the Moody Diagram. Finally, the Shear Stress by the following equation: =

f

2 / V

To use plant corrosion data of a specific crude or blend as a way to predict its corrosivity for an Calculate shear stress for plant with known corrosion data, (2) calculate shear stress for plant which is the specific crude or blend and (3) compare both shear stress. Corrosion rates are directly proportional Typically, the higher the acid content, the greater the sensitivity to velocity. When combined with hi 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 1% sulfur when no operating experience is available. When hydrogen sulfide is evolved, an alloy containin 9% chromium is preferred. In contrast to high-temperature sulfidic corrosion, low-alloy steels containing not seem to provide benefits over carbon steel in naphthenic acid service. 316 SS (with 2.5% Mo minimu SS with a higher Mo content (3.5% minimum) cladding of vacuum column is recommended when TAN i KOH/g and in atmospheric column when th e 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 wi reducing corrosion to an acceptable level. Blending of heavy and light crudes change shear stress para help reduce corrosion. Blending is also used to increase the level of sulfur content in the feed and i naphthenic acid corrosion.


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Injection of corrosion inhibitors may provide protection for specific fractions that are known to b 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 ra For long term reliability, upgrading the construction materials to a higher chrome and/or molybde solution. Laboratory Testing Several parameters need to be defined in planning a laboratory crude corrosion tests: (1) oil fraction, (2) temp stress (velocity), (4) alloy composition, (5) exposure time and (6) testing procedure. Laboratory corrosion correlated to refinery experience. Process Simulation Furnace Tubes and Transfer Lines - In furnace tubes and transfer lines, vaporization and fluid velocity a The high temperature conditions appears to activate even small amounts of naphthenic acid in oil increa significantly. Thus, at furnace tubes and transfer lines conditions, the influence of temperature, velocity vaporization is very large. Process conditions such as load and st eam rate and especially turbulence affe c The corrosion mechanism at the furnace tubes, transfer lines, areas of high turbulence such as thermowe is most likely an accelerated corrosion due to the velocity and the two-phase flow. Simulation of these c laboratory requires conditions of high degree of vaporization and relatively low wall shear stress . A rot with specimens in the vapor phase easily simulate the high velocity conditions found in the field. A flo 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 of condensates. There is very little effect of velocity. Corrosion takes only place in the liquid phase. It is condensate corrosion and is directly related to content, molecular weight and boiling point of the naphth Corrosion is typically severe at the condensing point corresponding to high TAN and te mperature. Simula tower corrosion requires the specimens to be exposed in the condensing phase and not in the vapor or liq requires apparatus common to corrosion studies in the chemical industry. An autoclave and a flow loop 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 showed a possible inhibition of NAC by sulfur compounds. In these conditions, an increase in velocity inc corrosion rates up to the point where impingement starts and corrosion is accelerated dramatically. The process is dependent on flow, temperature, materials of construction and naphthenic acid and H2S conte 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 ra very low since all evolved H2S is removed continuously by the continuous nitrogen purging, (2) seali where the evolved H2S and light components increase the pressure of the system, thus increasing corr (3) setting the pressure level arbitrarily to a certain point using a pressure relief valve and condenser. testing procedure details such as volume ratio of liquid to vapor, deaeration of autoclave, stirring of cleaning of specimens after test are also critical to the validity of the test results and need to be defi program. Conclusions High temperature crude corrosion is a complex problem. There are at least three corrosion mechanisms corres tubes and transfer lines where corrosion is dependent on velocity and vaporization and is accelerated by napht


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column where corrosion occurs at condensing temperature, is independent of velocity and increases concentration, and (3) side cut piping where corrosion is dependent on naphthenic acid content and is inhibit compounds. The industry still relies heavily on previous experience and readily available data on TAN and sulfur of opportunity crudes. Despite their shortcoming, rules of thumb are still used mainly because of lack of resources corrosion engineer. The uniqueness in process conditions, materials of construction and blend processed in each refinery and e variation in crude or blend processed does still not allow an accurate correlation of plant experience to laboratory corrosion tests. In addition to corrosion data, there is a need for better monitoring and recording of (temperature, velocity, and vaporization) and th e analytical data (TAN of cuts, ty pe of acid and sulfur compoun References and Further Reading Derungs, W.A., "Naphthenic Acid Corrosion – An Old Enemy Of The Petroleum Industry", Corrosion, 12 (2), 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(19 Craig, H.L., "Naphthenic Acid Corrosion in th e Refinery", CORROSION/95, Paper # 333, NACE, Houston, Te Craig, H.L., "Temperature and Velocity Effects in Naphthenic Acid Corrosion", CORROSION/96, Paper # 60 Texas, 1996. Heller, J.J., R.D. Merick and E.B. Marquand, "Corrosion of Refinery Equipment by Naphthenic Acid", NACE 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 o Volume 05.01. ASTM Method D664, "Test Method for Acid Number of Pet roleum Products by Potentiometric Titration", A Standards, Volume 05.01. UOP Method 565-92, " Acid Number and Naphthe nic Acids by Potentiometric Titration", UOP, Des Plaines, UOP Method 587-92, " Acid Number and Naphthe nic Acids by colorimetric Titration", UOP, Des Plaines, Illi Morrison B.L., D. DeAngelis, L. Bonnette and S. Wood, "The determination of Naphthenic Acids in Crude O 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 (1953). Slater, J.E, W.E. Berry, B. Paris and W.K. Boyd, "High Temperature Crude Oil Corrosivity Studies", API Pu 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 Oper North African Crudes", CORROSION/71, Paper # 39, NACE, Houston, Texas, 1971. Slavcheva, E., B. Shone and A. Turnbull, "Factors Controlling Napht henic Acid Corrosion", CORROSION/98, NACE, Houston, Texas, 1998. Blanco, E.F. and B. Hopkinson, "Experience with Naphthenic Acid Corrosion in Refinery Distillation Proces CORROSION/83, Paper # 99, NACE, Houston, Texas, 1983. Hau, J.L. and E.J. Mirabal, "Experience with Processing High Sulfur Naphthenic Acid Containing Heavy Cr Latin 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, "White R.A. and Ehmke E.F., "Materials Selection for Refineries and Associated Facilities", NACE, Houston, Babian-Kibala, E. et al.: "Naphthenic Acid Corrosion in a Ref inery Setting", NACE Conference, CORROSION 1993.


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Blanco, F. and Hopkinson, B.: "Experience with Naphthenic Acid corrosion in Refinery Distillation Process Conference, CORROSION 83, Paper #99, 1983. Scattergood, G.L. and Strong, R.C.: "Naphthenic Acid Corrosion, An Update of Control Methods", NACE Co CORROSION/87, Paper #197, 1987. Fau, Tseng-Pu, "Characterization of Naphthenic Acids in Petroleum by Fast Atom Bombardment Mass Spec Fuels, Vol. 5, No. 3, 1991: p. 371. Dzidic, I. et al., "Determination of Naphthenic Acids in California Crudes and Refinery Wastewaters by Fl 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 Tests", Corrosion/93, Paper #81, NACE. Tebbal, S. et al., "Review of critical Factors Affecting Crude Corrosivity", NACE Conference, CORROSION/ Tebbal, S. et al., "Assessment of the Corrosivity of Crude Fractions from Varying Feedstock", NACE Confe Paper # 498. Tebbal, S. et al., "Assessment of Crude Oil Corrosivity", N ACE Conference, CORROSION/98, Paper # 578 Tebbal, S., "Critical Review of Naphthenic Acid Corrosion", NACE Confe rence, CORROSION/99, Paper # 38 Tebbal, S., "Predict Naphthenic Acid Corrosion", Hydrocarbon Engineering, April 2000, Page 64.

Naphthenic Acid Corrosion

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