Crude Distillation Units

3100 Crude Distillation Units Authors: R.I. Piehl, Carol Ann Laughlin, D.J. (Don) Truax

Abstract This section covers materials of construction and other controls used to minimize corrosion in furnace tubes and transfer lines, atmospheric and vacuum columns, column overhead systems, and other crude distillation facilities. Corrosive agents include high-temperature H2S, naphthenic acids, and HCl. Contents

Page

3110 General Information

3100-3

3111 Corrosive Constituents in Crude Oil 3112 Mechanisms of Crude Unit Corrosion 3120 Crude Unit Furnaces

3100-9

3121 Furnace Tube Corrosion 3122 Furnace Transfer Line Corrosion 3130 Corrosion in Columns

3100-18

3131 Atmospheric Column Corrosion 3132 Vacuum Column Corrosion 3140 Atmospheric Column Overhead System Corrosion

3100-21

3141 Causes of Corrosion 3142 Process Controls 3143 Desalting 3144 Caustic Injection 3145 Wash Water Recirculation 3146 Neutralization 3147 Target pH Range of 7.5–8.0 3148 Corrosion Inhibitors

Chevron Corporation

3100-1

August 1999

3100 Crude Distillation Units

Corrosion Prevention and Metallurgy Manual

3149 Materials of Construction 3150 Monitoring the Corrosion Control System

3100-28

3151 Vacuum Column Overhead System Corrosion 3160 Other System Corrosion

3100-29

3161 Atmospheric Column Sidecut Stripper Corrosion 3162 Gasoline Rectifier Corrosion 3163 Corrosion in Piping and Valves 3164 Corrosion in Pumps 3165 Desalter Corrosion 3170 References

August 1999

3100-31

3100-2

Chevron Corporation



3110 General Information A large part of the corrosion encountered in petroleum refining can be attributed to the nature of the crude oil being processed. Although the hydrocarbons that constitute the majority of the crude oils are essentially noncorrosive, all crudes contain organic and inorganic impurities that may, under certain conditions, cause appreciable corrosion. Since crude distillation is the first major step in the refining of a crude oil, all of these corrosive constituents are normally present in the crude unit. Their effect on the corrosion of crude distillation equipment is discussed in this section.

3111 Corrosive Constituents in Crude Oil Sulfur Compounds Crude oil sulfur content varies from as little as a few hundredths of one percent to over five percent. While exceptions are frequent, typical sulfur contents of crudes from various sources are roughly as follows: United States

0.5 to 2%

Middle East

1 to 3%

Far East (Including Indonesia)

very low, often < 0.1%

Africa

0.2 to 1%

Venezuela

1 to 5%

In some crudes, sulfur exists in elemental form or as dissolved hydrogen sulfide. Slaughter, West Texas crude oil contains 0.68 weight percent hydrogen sulfide, and the gas from certain Wyoming sour crudes contains 6.45 volume percent H2S. These cases may, however, be regarded as extreme. The greatest percentage of sulfur in most crudes has been found to occur as organic sulfur compounds, of which mercaptans and disulfides are the most common.

Inorganic Salts As received by the refineries, all crude oils contain some quantity of inorganic salts, such as chlorides of sodium, magnesium, and calcium, sulfates, and carbonates. While these salts are sometimes found as distinct crystals in the crude, they most commonly occur in aqueous solution, having dissolved in the water accompanying the crude. The salt content of crude oils may vary from 2 pounds to 200 pounds per thousand barrels (PTB), but as received by refineries most crudes contain less than 30 PTB. Crudes shipped over the water in tankers generally average 10–15 PTB higher in salt content than those transported by pipeline.

Organic Acids Various types of organic acids are found in crude oils. In the case of a few crudes, they may exist in quantities large enough to constitute a serious corrosion problem during processing. Of these, naphthenic acids are the most common. Crude oils containing large quantities of naphthenic acid come from many locations, including

Chevron Corporation

3100-3

August 1999



California (Midway - Sunset, Kern), Venezuela (Merey, Lagotreco, Bachequero), Sumatra, the North Sea (Alba, Griffin), West Africa (Cabinda, Forcados, Qua Iboe, Escravos), and the Gulf of Mexico (main pass 299, Green Canyon). Highly naphthenic crudes likely to cause corrosion during processing are characterized by high neutralization numbers of the heavier petroleum fractions.

Other Corrosive Constituents Organic nitrogen compounds are found, to some extent, in all crude oils. These compounds are noncorrosive as they exist in the crude, and are sufficiently temperature-stable that they do not appreciably decompose during crude distillation. Although these nitrogen compounds are not a significant factor in crude unit corrosion, they can decompose and cause corrosion in downstream catalytic processes. Certain metallo-organic compounds are also found in crude oil. Vanadium compounds are particularly important in terms of corrosion. They do not contribute to process-side corrosion in crude units. However, when vanadium-containing oils are burned as furnace fuel, vanadium pentoxide is formed as a product of combustion. Vanadium pentoxide, as a major component of the fuel ash, can greatly accelerate the corrosion of tube supports and other furnace hardware which operate at temperatures above the point where the fuel ash becomes molten (1200°F–1300°F).

3112 Mechanisms of Crude Unit Corrosion Areas of crude distillation units particularly susceptible to corrosion are shown in Figure 3100-1. This section discusses the specific mechanisms of greatest concern in crude units.

Sulfur Corrosion Hydrogen sulfide is corrosive to carbon steel at temperatures above 500°F and may also contribute to corrosion and/or stress corrosion cracking at lower temperatures in the presence of liquid water. Since most crudes contain little dissolved hydrogen sulfide, it might be concluded that corrosion due to sulfur compounds should not be particularly serious in crude distillation units. Unfortunately, many of the commonly occurring sulfur compounds thermally decompose on heating to liberate hydrogen sulfide. It is this liberated H2S that is responsible for most high temperature crude unit corrosion in the form of high temperature H2S corrosion (also called sulfidation). [1] High Temperature H2S Corrosion (Sulfidation). The degree to which the sulfur compounds of various crudes decompose to liberate hydrogen sulfide is shown in Figure 3100-2. These data were obtained by a laboratory test involving heating the crude sample at a controlled rate and measuring the quantity of hydrogen sulfide evolved as a function of temperature. It is obvious from these curves that the different varieties of crude oil vary significantly in the rate at which hydrogen sulfide is evolved. While not apparent from the data, different crudes from the same general area may differ widely in H2S evolution characteristics. This is particularly true in the case of Arabian crudes. Imported crudes, as received at domestic

August 1999

3100-4

Chevron Corporation


Chevron Corporation

Fig. 3100-1 Corrosion Mechanisms in Crude Distillation Units

3100-5


August 1999



refineries, may also vary in hydrogen sulfide evolution as a function of their having been stabilized prior to shipment. Fig. 3100-2 Hydrogen Sulfide Evolution from Crude Oils, Chevron Proprietary Test Data

Since hydrogen sulfide is responsible for nearly all of the corrosion caused by sulfur compounds, it is possible to obtain some measure of the corrosivity of a crude oil by evaluating its tendency to evolve H2S upon being heated. For example, Figure 3100-2 suggests that Santa Maria crude would be far more corrosive at any temperature than Kettleman Waxy, and anyone familiar with the processing of these two crudes would agree. It is important to recognize that the hydrogen sulfide evolution test is a far better criterion of corrosivity than the sulfur content of the crude. Because sulfur compounds differ widely in resistance to thermal decomposition, it is not unusual to find high sulfur crudes that are less corrosive than crudes containing only a fraction as much sulfur. Results of hydrogen sulfide evolution tests on specific crudes may be obtained from CRTC Materials and Equipment Engineering if an interpretation of significance is desired; otherwise, directly from CRTC Process Planning.

August 1999

3100-6

Chevron Corporation



Wet H2S Cracking. At lower temperatures, where liquid water is present, wet H 2S cracking is a potential concern. In crude units, such cracking is possible in the column overhead and light ends systems. Refer to Section 450 of the Corrosion Prevention and Metallurgy Manual for guidelines on addressing wet H2S cracking concerns.

Corrosion by Inorganic Salts The quantity of inorganic salts present in a crude oil varies widely, depending on the composition of the brine from the oil well, the emulsification characteristics of the crude, the method of transportation and the time allowed during storage for settlement and separation of the water phase. The principal ingredients in this entrained water phase are the chloride, sulfate, and carbonate salts of sodium, magnesium, and calcium. Dissolved or particulate salts in the crude may cause plugging of feed heat exchange equipment. Hot brine may also corrode the bottom of desalter vessels and desalter effluent water piping. However, the most damaging effect of these salts results from the tendency of the chlorides to hydrolyze (react with water) at elevated temperatures to form hydrogen chloride (HCl). It is generally believed that magnesium and calcium chlorides hydrolyze readily, while sodium chloride does not. In the crude distillation unit, hydrogen chloride is formed primarily in the atmospheric and vacuum furnaces. While there is currently no evidence to indicate that it contributes to corrosion in either the furnaces in which it is formed or the hotter parts of the columns which it subsequently enters, the HCl ultimately finds its way into the overhead system of both the atmospheric and vacuum columns, where it is absorbed in the condensing water, forming highly corrosive hydrochloric acid.

Corrosion by Organic Acids As stated previously, the organic acids present in crude oil are largely naphthenic in nature, being based on a saturated ring structure. These acids remain largely unchanged during crude unit processing since temperatures of 750–900°F are needed for acid decomposition. While only a small amount of thermal decomposition occurs in a crude unit, naphthenic acids decompose and neutralization numbers and corrosion drop to nil in higher temperature downstream units such as thermal and catalytic cracking units. [6] Because most of the commonly occurring naphthenic acids are relatively high in molecular weight, they are seldom found in appreciable quantities in the lighter products from the crude unit. In those crude oils containing appreciable quantities of naphthenic acids, it is usually found that high neutralization numbers can occur in the entire VGO range (650–1000°F true boiling point (TBP)), where the acids are concentrated due to distillation. Naphthenic acid is a collective name for the various organic acids present in some crudes. The acidity of a crude, called neutralization number, is measured by titration with KOH. ASTM D-664, which uses potentiometric titration, is the most

Chevron Corporation

3100-7

August 1999



commonly used test. The test estimates two values: total acid number (TAN) and strong acid number. The neutralization number is the total acid number minus the strong acid number. As most crudes do not contain strong acid, the TAN is often equivalent to the neutralization number. Naphthenic acids cause corrosion because they convert normally protective iron sulfide into oil-soluble iron naphthenate. The acid may dissolve the iron sulfide scale entirely or only partially, leaving a poorly adherent material which is readily stripped off by high velocities or turbulence. There is a competition between H2S forming the scale and naphthenic acid dissolving it. At high neut numbers, any sulfide scale present is dissolved and corrosion occurs. See References [5], [6], and [7] for an in-depth discussion of naphthenic acid corrosion. As may be expected with any corrosive constituent, the degree of corrosion encountered with naphthenic acids will be higher in those areas where the acid is allowed to concentrate. In a crude unit, the areas of most severe naphthenic acid corrosion are usually in those parts of the columns (particularly the vacuum column) where the acids become concentrated by distillation. The potential for naphthenic acid corrosion is largely dependent on neut number (processing crudes with high neut numbers results in more corrosion). Previously published thresholds for corrosion were reliable for California crudes, but recent experience has shown the threshold may be different for other crudes. Some general guidelines are as follows: •

At low velocities, corrosion with California crudes has not been significant if the neut number for the hydrocarbon fraction is below 1.5 mg/gm.

•

At high velocities (>100fps, like transfer lines, furnace tube return bends, outlet headers), corrosion has been observed at neut numbers as low as 0.3 mg/gm.

•

These neut number thresholds do not hold true for all crudes. Some recent examples of corrosion are: –

–

–

A Chevron plant processing Venezuelan crude with a whole neut number of 0.4–0.5 experienced corrosion in the light gas oil system where the neut number was only 0.3–0.6. Another unit had atmospheric furnace outlet header and transfer line corrosion while processing West African crude blends with whole crude neut numbers less than 0.5. A third Company unit had corrosion of vacuum column packing in the overflash area, after processing North Sea and West African crudes. Neut numbers were not recorded during the time when corrosion occurred, but are believed to be less than 1.5 in draw streams.

In conclusion, we are still learning more about naphthenic acid corrosion. If you are processing a crude with no previous experience, contact CRTC Materials and Equipment Engineering for up-to-date advice. Assume that a crude with any naphthenic acid is potentially corrosive.

August 1999

3100-8

Chevron Corporation



The practical identification of naphthenic acid corrosion is usually based on the following factors: •

The appearance of naphthenic acid corrosion is highly characteristic, being typified by channeling, grooving, and the absence of corrosion products. Such corrosion is also highly sensitive to the effect of liquid velocity.

•

Unlike sulfur corrosion, naphthenic acid corrosion is no less a problem for chromium steels such as 4–6% Cr and 12% Cr than for carbon steel. Under certain circumstances this may also be true of Type 304L stainless steel. The key to naphthenic acid corrosion resistance is stainless steel with molybdenum (Mo) content greater than 2.5%. Type 316L stainless steel can contain 2.0–3.0% Mo. In the past, 316L was supplied with Mo contents in the middle of the acceptable range, so it had satisfactory resistance to naphthenic acids. Today, with improved steel making process control, 316L typically has Mo contents near the lower bound, which is insufficient for corrosion resistance. To ensure resistance today, 317L (3.0–4.0% Mo) is usually ordered, especially for severe services such as furnace transfer lines and structured packing. 317L cladding can be more cost effective than solid stainless steel for diameters above 6 inches.

•

Naphthenic acid corrosion can occur at temperatures as low as 350°F. Sulfur corrosion does not occur below 500°F, under dry conditions. For this reason, corrosion occurring in the 350°F–500°F range is probably caused by naphthenic acids.

•

A phosphorus-based corrosion inhibitor is being used on a trial basis at Pascagoula. Along with determining its effectiveness against naphthenic acid corrosion, the effect of phosphorus on fixed bed catalyst will be monitored. Contact Materials and Equipment Engineering at CRTC for more information.

Summary of Corrosion Mechanisms and Control Figure 3100-3 briefly summarizes the corrosives in crude oil, why corrosion occurs, where it is likely to be found, and methods of control. Figures 3100-4 through 3100-6 show the parts of the unit where each type of corrosion is likely to occur.

3120 Crude Unit Furnaces 3121 Furnace Tube Corrosion High Temperature H2S Corrosion (Sulfidation) Most furnace tube corrosion in crude units is caused by hydrogen sulfide. The severity of such corrosion is determined, primarily, by temperature and by the degree to which H2S will be liberated from the crude during heating. Laboratory data on the hydrogen sulfide evolution characteristics of several crudes are shown in Figure 3100-2. The carbon steel furnace tube corrosion rates caused by some of these crudes are given in Figure 3100-7. It will be noted that, for the three

Chevron Corporation

3100-9

August 1999



Fig. 3100-3 Corrosives in Crude Oil Corrosion Control Corrosive in Crude

Why Corrosion Occurs

Neutralize •

Yes (NH3, neutralizing amines)

•

Wash water recirculation also important

Inhibit

Magnesium chloride and calcium chloride decompose on heating to form HCl

Occurs where HCl and liquid water are present (typically column overhead systems)

Monel Cupro-Nickel Admiralty Carbon Steel

They thermally decompose to form H2S

Over 500°F metal temperature. Rate depends on temperature and H2S concentration

300 Series SS 12% Cr 9% Cr 7% Cr 5% Cr Carbon Steel

No

No

They are present in some crudes and go through the unit unchanged

Over 350°F, and where neutralization number is over 1.5, especially in high velocity turbulent areas (see text)

317 & 317L 316 & 316L (>2.5% Mo) Other 300 Series Carbon Steel

No

On trial basis at Pascagoula. Contact MEEU for current information.

Salts (HCl)

Sulfur Compounds (H2S)

Naphthenic Acids

Upgrade Alloy (Best to Worst)

Where Corrosion Occurs

No

Fig. 3100-4 Typical Areas Susceptible to H2S Corrosion in Crude Units

Atmospheric Column Vacuum Column

August 1999

3100-10

Chevron Corporation



Fig. 3100-5 Typical Areas in Crude Units Susceptible to Naphthenic Acid Corrosion

Atmospheric Column Vacuum Column

Fig. 3100-6 Typical Areas in Crude Units Susceptible to HCI Corrosion

Atmospheric Column

Chevron Corporation

Vacuum Column

3100-11

August 1999



crudes on which both corrosion and H2S evolution data are given, a direct relationship exists between these two variables. A quantitative relationship between H2S evolution, temperature, and corrosion rate is given in Figure 3100-8. At the H2S levels typically found in crude units, metal temperature is the most important variable affecting corrosion. While the corrosion data in Figures 3100-7 and 3100-8 are correlated with stock temperature, the actual rate of attack on furnace tubes is greatly influenced by the temperature of the tube wall. As might be expected from the corrosion rate curves, attack on furnace tubes is highly dependent on temperature distribution in the furnace. It is not unusual to find accelerated attack at hot spots on tubes, and a high eccentricity factor resulting from preferential corrosion on the fired side of the tube, as shown in Figure 3100-9. It does not necessarily require extreme localized overheating to create a situation in which essentially all of the corrosion occurs on the fired side of a radiant tube. As a rule of thumb, furnace tube corrosion rates double for each 35°F to 40°F increase in temperature. Fig. 3100-7 Corrosion of Carbon Steel Furnace Tubes by Various Crude Oils

Proper interpretation of the corrosion rate graphs requires some understanding of what the indicated temperatures mean. Actual corrosion rates are determined by metal temperature, not the temperature of the process fluid. For most plant equipment (columns, piping, etc.), the two temperatures are the same and corrosion rates could be plotted as a function of either one. However, this is not true of furnaces. Here, the metal temperature is considerably higher than stock temperature. To be

August 1999

3100-12

Chevron Corporation



Fig. 3100-8 H2S Corrosion of Carbon Steel Furnace Tubes

Fig. 3100-9 Furnace Tube Failure as the Result of Preferential Corrosion on the Fired Side

Chevron Corporation

3100-13

August 1999



technically correct, furnace tube corrosion rates should be plotted as a function of metal temperature, not stock temperature. But because we generally do not know the metal temperature, we plot corrosion rates as a function of stock temperature. Recognize that a given stock temperature will show a higher corrosion rate on a furnace tube plot than on a plot used for column corrosion rates. In other words, the corrosion rate at 600°F metal temperature might be plotted at 500°F stock temperature. The amount of temperature shift in the curves is equal to the difference between stock and metal temperatures. We commonly assume this to be on the order of 100°F. Carbon steel tubes are often used for the convection section of the atmospheric furnace. While this is often adequate, process and/or design changes can lead to convection section corrosion. For instance, switching from bare to finned tubes to improve heat transfer in the convection section can also promote high temperature sulfidation. If such changes are anticipated, consider using 5Cr convection tubes, as inspecting convection tubes for damage is difficult. For radiant section tubes, carbon steel is only suitable when processing low H2S crude at relatively low temperatures. Corrosion rates for 5-9%Cr tubes can be estimated by shifting the curves in Figures 3100-7 and 3100-8 upward in temperature. Shift the curves up by 150°F for 5Cr, 50°F more for 7Cr, and another 50°F for 9Cr. Where corrosion of carbon steel is excessive, substantial benefit can be obtained through the use of the chromium steels as long as the crudes being processed are not high in naphthenic acids. The most commonly used material is 5% Cr - ½% Mo steel which has been found adequate in all but the most severe conditions. For the hottest parts of furnaces that handle extremely sour crudes, 7% or 9% Cr steels are sometimes required.

Naphthenic Acid Corrosion Furnace tube corrosion by naphthenic acids has increased greatly during recent years, because our refineries are processing more San Joaquin Valley “SJV” and other naphthenic crudes. One of the early case histories came from a unit feeding Midway Special (California) Crude. Here, 4–6% Cr furnace tubes suffered corrosion where stock temperatures exceeded 700°F. It was felt that attack was due to naphthenic acids, because the corrosion of this material was much higher in this environment than it was in a higher sulfur but low naphthenic Arabian Crude environment. This is illustrated in Figure 3100-10. Additionally, the corrosion of both carbon steel and 4-6% Cr showed the “washed out” effect characteristic of naphthenic acid corrosion (see Figure 3100-11). Residuum stripper units at both Richmond and El Segundo Refineries have suffered naphthenic acid corrosion of 5, 7, and 9% Cr tubes. Corrosion took the form of wash-outs at the outlet ends of the last tube pass. Three factors cause naphthenic acid corrosion to occur near the furnace outlets. First, temperatures are highest there. Second, fluid velocities are highest at that point, owing to vaporization of the lighter constituents in the crude. Third, vaporization of the lighter constituents causes the naphthenic acids to concentrate in the unvaporized liquid because the acids tend to have high boiling points. It should be

August 1999

3100-14

Chevron Corporation



Fig. 3100-10 Furnace Tube Corrosion by Crudes Containing Naphthenic Acids and Evolving H2S

noted here that naphthenic acid corrosion is a liquid phase phenomenon. In a twophase system, it is the liquid phase that is corrosive. Corrosion can also occur in the vapor if mist or liquid droplets are present. Some crude units require higher alloys than the 5-9% Cr steels for furnace tubes when processing the very highly naphthenic crudes like SJV. Better materials, in order of increasing corrosion resistance, are the 18-8 stainless steels (Types 304, 304L, 347), 16-13-3 Cr-Ni-Mo stainless (316 and 316L), the slightly higher alloyed 317 and 317L Cr-Ni-Mo stainless steels, and Inconel 625. The exact service limits for these materials, in terms of temperature and neutralization number, have not yet been established. Choice of furnace tube materials for high-naphthenic service is best made after reviewing field experience of various materials in the most similar crude service. When selecting stainless steel furnace tube materials, the possibility of polythionic acid stress corrosion cracking should also be considered. See the Corrosion Prevention and Metallurgy Manual, Volume 1, Section 400 for a detailed discussion of this phenomenon. When considering both naphthenic and polythionic attack at the same

Chevron Corporation

3100-15

August 1999



Fig. 3100-11 Effect of Naphthenic Acid Corrosion on a Carbon Steel Furnace Tube

time, Type 347 stainless may be adequate if naphthenic acid corrosion is mild; this alloy has the best resistance to sensitization and polythionic acid attack. If a molybdenum-containing grade is needed for naphthenic resistance, use Type 316L (2.5% Mo min) or 317L. These materials may sensitize in time. To avoid eventual polythionic attack, it is important to minimize the tubes’ exposure to water and oxygen. In some cases, plants utilize a carbonate wash procedure and dehumidifiers during the shutdown process.

August 1999

3100-16

Chevron Corporation



Naphthenic acid corrosion is an extremely complicated subject. References [5], [6], and [7] present the most comprehensive discussion of the subject. In the preceding discussion, no distinction has been made between atmospheric and vacuum furnaces. The same general corrosion considerations are true in both furnaces. The primary difference is that somewhat higher corrosion rates can usually be expected in the vacuum furnace because of higher temperatures.

3122 Furnace Transfer Line Corrosion Like furnace tubes, transfer lines may be subject to corrosion by either hydrogen sulfide or naphthenic acids. H2S corrosion of a transfer line which is not externally heated will be lower than that of a furnace tube of the same material operating at the same stock temperature. Because metal wall temperatures are relatively uniform, transfer lines will not show the highly eccentric corrosion commonly found in furnace tubes as a result of differential temperatures. However, with highly naphthenic crudes, transfer line corrosion may be greatly influenced by turbulence. Localized attack may occur at welds, bends, and particularly at tees where the pressure drop in the line results in sudden vaporization (flashing) of the hydrocarbons and, hence, extreme turbulence. Carbon steel transfer lines may show adequate corrosion resistance when processing the milder crudes at relatively low transfer line temperatures. The 5% Cr steel is a common transfer line material and generally performs well in sour crude service. However, this alloy does have certain limitations. It is not likely to be satisfactory in plants feeding highly naphthenic crudes. And in Middle East crude service, 5% Cr steel may experience H2S corrosion if transfer line temperatures approach the 750°F to 800°F level. Another disadvantage of 5% Cr steel is difficulty of fabrication. Welds require preheat and postweld heat treatment to avoid cracks during welding and to ensure good mechanical properties in the weldment. Type 304 stainless has been used for transfer lines in the past. It has better resistance to H2S and naphthenic acid corrosion than 5% Cr, and the installed cost is often lower than 5% Cr. In most cases, performance has been excellent. However, Type 304 will sensitize from the heat of welding, or from prolonged exposure to operating temperatures above about 700°F. This renders the material susceptible to polythionic acid stress corrosion cracking during shutdowns. The incidence of such failures has been low, but some have occurred. This has led to the use of stabilized grades of stainless such as Type 347 or thermally stabilized Type 321 (heat treated at 1650°F after welding) in place of 304. Units handling highly naphthenic crudes may experience localized corrosion of the 18-8 stainless steels (Types 304, 304L, 321, 347) at points of high velocity or turbulence. Bends (especially miters), tees, and thermowells have been common sites for corrosion. Accelerated attack has also occurred downstream of thermowells and at pass control valves at the furnace outlet. Localized attack like this is difficult to predict. Several crude units have upgraded the entire transfer line to 316L or 317L because of the inability to predict where the next leak might occur.

Chevron Corporation

3100-17

August 1999



When low-carbon grades of stainless steel such as 316L and 317L are used for transfer lines, the possibility of their sensitizing in service must be considered. If the line operates above about 700°F, sensitization is likely and limiting contact with air and water is critical. If the line must be opened to the atmosphere, carbonate washing is desirable to minimize the chance of polythionic acid cracking.

3130 Corrosion in Columns 3131 Atmospheric Column Corrosion Most corrosion encountered in an atmospheric column is caused by corrosives formed in the atmospheric furnace, including hydrogen sulfide and hydrochloric acid. The major concern is the nature and control of corrosion caused by the presence of hydrogen sulfide. Hydrochloric acid can cause considerable damage to the upper part of the atmospheric column. This will be discussed in Section 3140. Naphthenic acids are seldom found to cause corrosion in the atmospheric column because the acids do not concentrate at typical atmospheric column temperatures. It is a general rule that dry sulfur corrosion, or, more properly, hydrogen sulfide corrosion, occurs at the maximum rate in the flash zone. This is to be expected, since temperature, H2S concentration, and turbulence are at a maximum in this area. Within the flash zone itself, corrosion of carbon steel is usually severe, except when processing an extremely mild crude at relatively low temperatures. Corrosion may be particularly severe at points of high turbulence or direct impingement against the metal. Control of such corrosion is usually accomplished with a lining or cladding of Type 405 or Type 410S steel (12% Cr). Types 304, 321, or 347 stainless steel, while completely adequate in this location, are seldom required. Above the flash zone, temperatures progressively decrease in an upward direction through the column. This drop in temperature is accompanied by a decrease in hydrogen sulfide corrosion. Corrosion is possible wherever temperatures exceed 500°F, but significant corrosion usually does not occur below 575°F. Figure 3100-12 shows typical column corrosion rates as a function of H2S concentration and temperature. These data apply only to the part of the column above the flash zone. Within the flash zone, corrosion rates will be higher than the curves predict, due to turbulence. Below the flash zone, H2S content is both low and impossible to determine, so these correlation curves cannot be used. Figure 3100-12 is equally applicable to vacuum columns, but only when naphthenic acid concentrations are low. When using Figure 3100-12, H2S concentration can be calculated from the H2S evolution curve for the crude in question. Below the flash zone, in the stripping section, corrosion rates tend to decrease because the hydrogen sulfide is being stripped out of the oil and swept upward in the column. Where bottoms temperatures are below about 650°F, carbon steel has generally proven adequate for the stripping section and bottom head. Above 650°F bottoms temperature, carbon steel may corrode at high rates, and alloy protection is often required (see Figure 3100-13). This is presumed to be the result of the organic

August 1999

3100-18

Chevron Corporation



Fig. 3100-12 Typical H2S Corrosion Rates Above the Flash Zone in Crude Columns

Fig. 3100-13 Corrosion of Crude Column Bottom Heads

Chevron Corporation

3100-19

August 1999



sulfur compounds in the oil continuing to decompose and liberate fresh hydrogen sulfide. Where this has occurred, it is typically found that the bottom head corrodes more rapidly than the column shell in the stripping section area. H2S corrosion can also occur on the reduced crude side of bottoms exchangers. It is interesting that the corrosion rates in the flash zone may be increased significantly with any given crude by increasing the outlet temperature of the atmospheric furnace. This results in a higher flash zone temperature, as well as an increase in evolved H2S. A secondary result is that because of higher H2S concentrations the rate of corrosion within the entire column will be raised. The relative order of corrosion resistance of various alloys in the atmospheric column is also important. While carbon steel is subject to corrosion in varying degrees in the flash zone area, it usually has adequate resistance in most other areas of the column. The chromium steels and chrome-nickel stainless steels are usually good. Trays and strip lining of 12% Cr steel are necessary above the flash zone when processing crudes such as Arabian Light which evolve high amounts of H2S. Nonferrous materials such as Monel and the copper-base alloys will be severely corroded in any part of the column where temperatures exceed about 500°F. Historically, little naphthenic acid corrosion has been experienced in atmospheric columns. But some danger of naphthenic acid attack may exist in the atmospheric columns of single stage crude units. Conditions favoring its occurrence are highly naphthenic crude feeds, and high transfer line temperatures (over 700°F). Under these conditions, the hottest sidecuts could contain enough naphthenic acids to be corrosive. Naphthenic acid corrosion is covered in Section 3132.

3132 Vacuum Column Corrosion Since hydrogen sulfide is released from the crude oil in both the atmospheric and vacuum furnaces, the same general problem of H2S corrosion exists in atmospheric and vacuum columns. In either instance severity of corrosion depends both on operating temperatures and on the characteristics of the crude oil being processed. In general, the methods of H2S corrosion control are similar for both atmospheric and vacuum columns. Only for extremely mild crudes and low column temperatures is carbon steel completely acceptable in vacuum column service. In most cases, alloy lining or cladding is required, at least in the flash zone. With extremely sour crudes, considerably more alloy protection may be needed. With Middle East crudes, for example, alloy cladding and trays are needed wherever temperatures exceed 600°F. The 12% Cr steels (such as Types 405 and 410S) provide almost complete resistance to hydrogen sulfide corrosion under vacuum column conditions. In most naphthenic crudes, the acidic constituents are found primarily in the gas oil and light lubricating oil fractions, and are chemically related to the purely hydrocarbon components of these fractions. During crude distillation, the naphthenic acids will, in most cases, tend to concentrate within the vacuum column above the feed tray. The most severe attack is often confined to several trays. Severe

August 1999

3100-20

Chevron Corporation



naphthenic acid corrosion may ultimately require alloy protection throughout the column. Unlike the atmospheric column, the vacuum column itself may be subject to severe naphthenic acid attack when highly naphthenic crudes are being processed. Such corrosion is typified by sharp-edged channels and grooves in areas of high fluid velocity and the absence of corrosion products (because most metal naphthenates are oil-soluble). Packing is particularly susceptible. Company units have seen structured packing corrode in columns where sidecut neut numbers were believed to be well below 1.5. For crude oils high in naphthenic acid, it is necessary in most cases to protect the vacuum column with Type 316L (> 2.5% Mo) or 317L stainless steel. The extent of protection depends on the distribution of naphthenic acids within the column. Alloys less expensive than Type 316L stainless steel, such as Types 304L, 321, and 347 are an improvement over carbon steel in such environments, but usually do not provide long enough lives. Company experience has shown that naphthenic acid corrosion is seldom significant below about 350°F. At higher temperatures, naphthenic acid attack may be expected if the neutralization number of the sidecut stream exceeds 1.5 mg potassium hydroxide (KOH) per gram. On rare occasions, vacuum column top heads have suffered corrosion at temperatures above the boiling point of water but below 350°F. This temperature range is too high for hydrochloric acid corrosion, and too low for naphthenic acid attack. Although this corrosion has occurred in plants processing naphthenic crudes, the appearance of corrosion is smooth, unlike typical naphthenic acid corrosion. The best current theory is that such corrosion is due to other acidic organic compounds, like phenols, and is possibly accelerated by the presence of chlorides [6]. When this type of corrosion is encountered, the remedy has been to line the affected areas with Type 316L stainless. Neutralization is not an effective remedial measure.

3140 Atmospheric Column Overhead System Corrosion 3141 Causes of Corrosion Corrosion Control Philosophy Chevron developed effective technology to prevent overhead system corrosion in the early 1970’s and incorporated that technology into the crude units built after that time. The concept involves operating the top of the atmospheric column hot enough to keep potential corrosives in a harmless vapor state (staying above the water dewpoint, usually 270°F minimum) and quenching and water saturating the overhead vapors in the pipe between the column and the first condenser with alkaline recycle water (recycle water with neutralizer added). This avoids neutralizer salt sublimation, the low pH initial condensate, and the even lower pH condensate due to partial water re-evaporation. Recycling water with neutralized salts also buffers the condensate from the overhead stream and greatly stabilizes pH. With this

Chevron Corporation

3100-21

August 1999



system, carbon steel corrosion control simply requires adequate water recycle and pH levels above the threshold for carbon steel corrosion. Without saturation water recycle, corrosion control is exceedingly complex. Although other corrosion control methods such as desalting and/or caustic injection are often used along with wash water recirculation, these methods become even more important if water recycle is not used. Also, alloy tubes are usually required for the initial condensate and water reboiling region. If copper based tubes are used, two sided pH control is needed to avoid corrosion of the copper alloy at high pH and the carbon steel and copper components at low pH. In general, this approach to corrosion control follows the Crude Unit Atmospheric Overhead Corrosion Control Best Practice [8]. Although the Best Practice’s approach differs from the rest of the industry, Chevron has successfully designed and operated crude unit overheads with this philosophy since the early 1970’s.

Specific Corrosives Due to both the use of stripping steam in the atmospheric column and the presence of water in the crude feed, large quantities of moisture are invariably present in the atmospheric column. This moisture is, for the most part, condensed in the atmospheric column overhead-feed exchangers and overhead condensers. Where vapor line temperatures are low (on the order of 200°F), water may also condense in the top of the atmospheric column. As a result, corrosion problems caused by liquid water will be found throughout this area. For simplicity, the following discussion includes the top few trays of the atmospheric column. As mentioned, chloride salts in the crude oil form hydrochloric acid at elevated temperatures by hydrolysis. This reaction occurs during heating of both atmospheric and vacuum column feed streams. The acid thus formed enters atmospheric and vacuum columns and eventually leaves with the overhead product. Since HCl is water-soluble, it is absorbed in any moisture that may condense, forming a strongly acidic solution. While there is no evidence that HCl has any corrosive effect in the crude distillation unit in the absence of liquid water, aqueous hydrochloric acid solutions are the primary cause of corrosion in the overhead system, where liquid water normally exists. Corrosion can also occur in the top part of the atmospheric column, if liquid water exists. Although not the primary corrosive, hydrogen sulfide also contributes to overhead system corrosion. The usual corrosion products formed in overhead equipment are iron and copper sulfides (on steel and copper alloys respectively). Metal sulfides will either be stable or unstable (they will form or dissolve), depending on pH in the system. Both iron sulfide and copper sulfide dissolve at low pH while copper sulfide also dissolves at high pH. This is a fundamental reason why acid conditions (low pH) corrode both copper alloys and steel, while alkaline conditions (high pH) corrode copper alloys.

August 1999

3100-22

Chevron Corporation



3142 Process Controls In the hotter areas of the crude unit, corrosion is almost exclusively controlled by the use of suitably resistant alloys. In the crude unit overhead system, however, process controls can minimize corrosion. Injecting water into the atmospheric column overhead system dilutes the corrosives and stabilizes the pH. Hydrochloric acid can be neutralized with a volatile alkaline material such as ammonia or neutralizing amine. The amount of HCl going to the overhead system can be reduced by good desalting and the addition of caustic (sodium hydroxide) to the crude feed. Proper process control should provide a minimum of 10 years life for carbon steel overhead piping and have a goal of five years minimum life for carbon steel exchanger tube bundles.

3143 Desalting The first place in the crude unit process flow where overhead corrosion can be influenced is in the desalter. Both chemical and electrical desalting are used in Chevron crude units. It is important that the desalter provide a consistently low salt content. A variable salt content introduces a control problem, because changing amounts of HCl result in pH swings in the overhead system. Monitoring of pH and controlling it by constantly varying the rate of neutralizer injection then becomes very difficult. Recovered oil can be an important cause of pH instability. From the corrosion engineer’s view point, the recovered oil should be added to the crude as far upstream as possible to facilitate removal in the desalter. If it is fed directly to the atmospheric column because of heat exchanger and furnace fouling concerns, recovered oil raises the average amount and variability of chlorides going overhead. Any sources of increased or fluctuating chloride levels increase the difficulty of controlling overhead pH and corrosion.

3144 Caustic Injection Similar to good desalting, caustic injection is a very effective way of reducing HCl going to the overhead. When injected into the crude between the last crude preheat exchanger and the atmospheric furnace, caustic (sodium hydroxide) combines with HCl as it forms. As a result, the chlorides leave the plant in the vacuum column residuum stream, as undecomposed sodium chloride. With good desalter operation and caustic addition to the crude, it should be possible to reduce overhead chloride levels to 10–20 ppm, as measured in the accumulator drum water. While caustic injection helps reduce overhead corrosion, it can cause other problems if not properly applied. These problems include:

Chevron Corporation

•

Concentrated caustic can cause stress corrosion cracking and general corrosion of piping and exchangers downstream of the injection point.

•

Caustic can damage downstream catalysts.

•

Caustic can cause furnace fouling. This phenomenon has not been seen in crude furnaces, but it has occurred in coker furnaces.

3100-23

August 1999


•


Caustic can cause unacceptable sodium carryover in the coke produced in coker units.

Risks of stress corrosion cracking and corrosion can be mitigated by utilizing the Caustic Injection Facilities Standard Design [2]. Where crude unit residuum is fed to a coker or a catalytic process, such as an RDS, the risks to the catalyst must be studied before injecting caustic in the crude unit.

3145 Wash Water Recirculation One important element of an overhead corrosion control system is atmospheric overhead condensed water recirculation. Carbon and low alloy steel corrosion first occurs where heat exchange surfaces operate below the water dew point and vapors are above the water dew point. In this region, water, HCl, and neutralizer condense together, and then partially or completely evaporate. During evaporation, water and neutralizer preferentially return to the vapor while chloride ions remain in the aqueous phase resulting in a low pH. Neutralizers are ineffective in this region. Saturation water recycle is the only way to control this problem of condensation/evaporation. With saturation water recycle, the water vaporization cools the overhead vapor stream to its water dew point (or below). This avoids both the depressed pH and the high HCl content of the dewpoint liquid. The large reservoir of recirculating water greatly contributes to pH stability, making pH control much easier. Quenching through the water dewpoint also prevents ammonium chloride salt deposition and underdeposit corrosion. Saturation water recycle involves withdrawing the condensed water from the accumulator drum, and reinjecting it into the overhead vapor line. The water should be injected through a distribution nozzle pointing downstream. It should be located as far upstream of the first overhead exchanger as possible to promote mixing and vaporization. The water recirculation rate must use 30–70% more water than would be required if equilibrium were achieved, in order to achieve saturation and to insure that a reasonable percentage of the water remains unvaporized. Similar to any injection point, the recycle water injection area should be monitored for corrosion. We have seen corrosion of the overhead line where inadequate mixing occurred. Empirical methods are required to assess whether or not saturation has been achieved and to establish operating guidelines to consistently achieve saturation. A simple method, in concept, is to measure vapor temperature as a function of water recycle rate. At saturation, the reduction in vapor temperature with increasing recycle rate abruptly ceases. Measuring vapor temperature with nearby liquid at a substantially different temperature is not simple and requires some experimentation. The most significant disadvantage of water recirculation is loss of preheat obtained in the overhead-feed exchangers. Chevron units built since the 1970’s have been designed to accommodate water recirculation, but earlier units may be impacted by the loss of preheat. Another disadvantage is that wet reflux back to the column results in tray salting and corrosion. Chevron experience, however, is that the benefits of water washing generally far outweigh the disadvantages.

August 1999

3100-24

Chevron Corporation



3146 Neutralization No matter how effective desalting and caustic injection may be, some hydrogen chloride (HCl) will always be evolved when the crude is heated. Being volatile, the HCl will go overhead in the atmospheric and (to a lesser extent) the vacuum columns. It will be absorbed in the condensing water, where it will form a hydrochloric acid solution. This acid is so corrosive that without process control countermeasures, corrosion prevention would require the use of expensive alloys such as Hastelloy B or Hastelloy C. Water recirculation dilutes the acid, but neutralization is required to raise the pH. The industry has adopted the practice of neutralizing the acid by injecting either ammonia or a neutralizing amine into the overhead system. The Company Best Practice is to use aqueous ammonia as the neutralizer, unless a plant’s specific design and operation limit its effectiveness. If questions about the appropriate neutralizer arise, consult with a Company Materials Engineer. The choice should not be left to chemical suppliers, who may overemphasize the benefits of their chemicals and downplay the disadvantages.

Ammonia Ammonia is an excellent neutralizer, is readily available, is relatively inexpensive, and causes no downstream fouling problems. In the aqueous form it is also convenient and easily controlled. Anhydrous ammonia is not recommended because injection rates are hard to control and greatly influenced by atmospheric temperature changes. Anhydrous or aqueous ammonia can be purchased, but they should be diluted to a 10 wt % solution before injection into the crude unit overhead. Dilution water should contain no more that 25 ppm of total dissolved solids in order to prevent deposition in the overhead system. The ammonia should be injected into a sidecut stripper vapor return line or (preferably) into the column overhead vapor line through an injection nozzle and reliable pumping system. An accurate and reliable measurement of ammonia flow rates is also important for maintaining system control. Design recommendations are further detailed in the CRTC document “Design Recommendations Aqueous Ammonia System Corrosion Control Crude Until Overhead Systems”. [3] If water injection is sufficient to achieve saturation, evaporation ceases and ammonia neutralization becomes effective. As the vapors pass through the overhead system and are cooled, increasing amounts of condensing water remain as liquid. HCl and neutralizer are absorbed at different rates. In an HCl/NH3 system, the HCl is absorbed more rapidly, so the initial liquid is relatively acidic. As condensation proceeds, more ammonia is absorbed in the liquid and the pH rises. Corrosion continues wherever low pH water is present. Unfortunately if water injection is insufficient, corrosive ammonium chloride deposits can form. As condensing water has a dew point, condensing ammonium chloride has a sublimation point. Depending on the conditions in the plant, either ammonium chloride or water may condense first. If water condenses first, the ammonium chloride dissolves in the water and no salt deposits form. If ammonium chloride condenses first (sublimes), salt deposits form. When ammonium chloride

Chevron Corporation

3100-25

August 1999



salts deposit on colder surfaces, water vapor permeates the deposit and condenses on the surface. The resulting aqueous ammonium chloride film is highly corrosive and causes pitting.

Neutralizing Amines Chemical vendors have long advocated the use of neutralizing amine rather than ammonia for overhead pH control. They claim that using amines prevents the low pH in the initial water condensate which is ascribed to ammonia. They fail to point out these disadvantages, however: •

Amines are much more expensive than ammonia.

•

Their high cost prohibits using enough to raise the pH to an optimal level.

•

Condensation of corrosive amine hydrochloride salts can occur at temperatures well above the water dew point.

•

Neutralizing amines and their reaction products can cause fouling, corrosion, and carry chlorides into downstream processes.

This discussion of neutralizers has focused on the atmospheric column. Similar corrosion can also occur in the vacuum column overhead system. However, severe corrosion seldom occurs, and it is easily remedied by addition of a small quantity of ammonia.

3147 Target pH Range of 7.5–8.0 Maintaining overhead accumulator water in the 7.5–8.0 pH range minimizes corrosion in mixed carbon steel and copper alloy metallurgy systems. Drum pH of 7.5 to 8 produces carbon steel corrosion rates less than 10 mpy in flow environments where vapors are water saturated. Acid water corrosion of carbon steel increases with decreasing pH. One pH point less increases corrosion rates an order of magnitude or more in flow environments. Zero corrosion rate of carbon steel requires saturation water recycle and drum pH greater than 8. Conversely, copper alloy corrosion from ammonia occurs at high pH and accelerates with increasing pH. In addition, raising ammonia concentration will lower the ammonium chloride precipitation (sublimation) temperature and lead to neutralizer salt corrosion and plugging. Operation at the highest pH below the ammonium chloride sublimation point is the best for carbon steel. Therefore, 7.5–8.0 pH is the best compromise for mixed metallurgies. Another reason for not controlling to a pH above 8 is that pH is no longer a good indicator of the amount of ammonia present. NH4HS buffers at about pH 8.5, so additional NH3 just forms more NH4HS and does not produce a pH change.

3148 Corrosion Inhibitors Theoretically, filming amine corrosion inhibitors function by forming a thin, adsorbed film on the metal surface. This film prevents contact between the

August 1999

3100-26

Chevron Corporation



corrosive constituents and the metal. These high molecular weight, organic liquids have some affinity for both oil and water. They are non-volatile, so they are not present in the vapor phase. Since the water phase in overhead systems causes the corrosion, a filming amine that has a preferential affinity for water would be a likely choice for corrosion prevention. However, these filming amines are washed away by flowing water, especially in high velocity areas, and do not provide adequate protection. Filming amines that have a preferential affinity for oil often do not reach the surfaces that are water wetted, so they also fail to protect. In addition, any dead areas in the system that are not liquid wetted will not be protected by the non-volatile filmers when condensation and evaporation occur. Besides their lack of effectiveness, filming amines can actually create problems. Concentrated filmers may be corrosive. If they are not carefully diluted and injected, they will corrode carbon steel. Inhibitors can cause fouling. They can leave gummy deposits in instrumentation, reboilers, and heat exchangers in downstream equipment. A final and compelling argument against using inhibitors is that they may not be necessary. If both overhead system design and corrosion control program are good, corrosion rates will be low enough to make an inhibitor unnecessary. Although chemical vendors may disagree, there is no justification for spending money on filming amines in crude unit overheads.

3149 Materials of Construction If process controls have not given adequate life to overhead exchanger carbon steel tubes and if water recirculation is not feasible, more corrosion resistant and more expensive tube materials can be used. 70-30 Cu-Ni, admiralty brass, Monel, and titanium (ASTM B-338, Grade 2) all have better resistance to HCl corrosion than does carbon steel. However, admiralty brass can fail by ammonia stress corrosion cracking at a high pH and Monel is not widely used in the industry because it is very expensive. Some titanium alloys can rapidly pit under salt deposits if tube metal temperatures exceed 250°F–300°F. This was also a problem when Chevron used overhead saltwater cooled condensers. If they were water-starved, they would plug up with waterside salt deposits. Where temperatures are high enough to cause chloride pitting of Grade 2 titanium, Grade 7 has been used with good success. One Company refinery standardized to Grade 7 for salt water cooled condensers where stock inlet temperatures exceeded 250°F. Corrosion in the top part of the atmospheric column is seldom so severe that an alloy is required. As long as it is kept warm enough to stay dry and neutralizing amine hydrochloride salts are not present, the top of the column will not corrode. However, some older crude units with condensation in the top of the column have shown enough metal loss after 15 to 25 years to require alloy lining. Monel or 6% Mo stainless steel is typically used, since 12% Cr steel will pit badly and the austenitic stainless steels are subject to chloride stress corrosion cracking. Copper alloys suffer wet H2S corrosion. 70-30 Cu-Ni valve trays failed in areas where repeated motion at valve guides eroded off the protective sulfide scale.

Chevron Corporation

3100-27

August 1999



Atmospheric overhead vapor lines are constructed of carbon steel. Typically, corrosion is more moderate and alloys such as Monel are seldom justified. However, some potential for corrosion exists here, and vapor lines should be routinely inspected by ultrasonic and/or radiographic techniques, particularly at bends and just downstream of bends and at injection points.

3150 Monitoring the Corrosion Control System No corrosion control system can be effective unless it is working properly. The following monitoring and maintenance is required.

August 1999

•

Monitor pH with a continuous pH analyzer. Chloride content in crude units can be highly variable over time, so the overhead HCl concentration, neutralizer demand, and pH will change as well. Continuous pH analysis is necessary to observe and react to these trends. Periodic sampling can be used as a back up to on-line continuous analysis, but it is insufficient for the tight control required for minimizing corrosion.

•

Maintain and calibrate the pH analyzer on a regular basis. Since pH is measured in the accumulator water, oil and solids will be present that are detrimental to on-line sampling and measuring devices. The Crude Unit Overhead pH Analyzer System recommended in the Best Practice is designed to minimize the effects of these contaminants and provide reliability.[8]

•

In conjunction with continuous pH analysis, it is important to have board mounted control of the ammonia injection system. With fluctuating overhead acid concentration, frequent adjustments to the ammonia flow rate are required to maintain the proper pH. This is much more efficiently and easily done if the flow rates are changed in the control room.

•

Maintain all chemical injection pumps, flow meters, and instrumentation so that the system is a reliable, continuous ammonia (or caustic) source.

•

Ultimately the best way to adjust ammonia injection and maintain the correct pH range is with closed loop control. By configuring the pH monitor system to control the ammonia injection, changes in control can be instantaneous and operators can be freed from the responsibility of frequent adjustments. Obviously this approach can only be implemented when a reliable on-line analyzer and ammonia delivery system are in place. Once this is established and the loop has been closed, periodic checks will be necessary to ensure that the system is working properly.

•

Monitor the salt content of desalted crude and the chloride content of accumulator drum water.

•

Continuously monitor corrosion with probes located at the inlets and outlets of the overhead exchangers, and other areas that show signs of corrosion.

•

Be alert for changes in process conditions that might indicate a need for additional monitoring or a shift in the corrosion control program. For example, note

3100-28

Chevron Corporation



any large change in overhead vapor line temperature or a change to a new crude that is difficult to desalt. •

Inspect overhead piping onstream and equipment during turnarounds to identify any problems or inadequacies in the corrosion control program.

3151 Vacuum Column Overhead System Corrosion The fundamental causes of corrosion in the vacuum column overhead system are similar to those in the atmospheric overhead, but are complicated by additional factors. The use of a steam jet ejector to create the vacuum results in a system containing largely steam or water, with other constituents present in smaller quantities. In addition, the existence of a vacuum introduces the possibility of air leakage into the system. In the absence of air leakage, corrosion tends to be less severe in the vacuum column overhead system than in the atmospheric. While both hydrogen chloride and hydrogen sulfide are typically present, the quantity of HCl is likely to be less than in the atmospheric overhead. In addition, the problem of ammonium chloride deposition is seldom encountered. However, air leakage into the system creates a condition not encountered in the atmospheric overhead. Where air leakage occurs, corrosion and scaling of both steel and copper alloys can be severe and cannot effectively be controlled by addition of ammonia or corrosion inhibitors. If air entry into the vacuum system is prevented, acceptable corrosion protection is generally obtained through aqueous ammonia injection to control acidity. As in the atmospheric overhead system, it is important to avoid excessive use of ammonia, which could lead to corrosion and stress corrosion cracking of copper alloy condenser tubes. During the 1980’s, Chevron had several experiences with significant corrosion (40–120 mpy) in vacuum column overheads and light gas oil sidecuts [6]. Corrosion occurs at temperatures of 350-420°F, which is not hot enough for high temperature H2S corrosion, but is too high for aqueous corrosion. The corrosion appears to be controlled by a different mechanism than traditional naphthenic acid corrosion. Whereas naphthenic acid corrosion commonly appears as grooving and pitting, this corrosion is smooth in appearance. Although the exact mechanism is not known, the current thinking is that the corrosion is caused by light naphthenic acids in combination with phenols and possibly chlorides.

3160 Other System Corrosion 3161 Atmospheric Column Sidecut Stripper Corrosion In general, atmospheric column sidecuts contain no significant corrosive constituents other than a small quantity of dissolved hydrogen sulfide, which is readily removed in the sidecut strippers. As a result, carbon steel is almost invariably adequate for the sidecut strippers and suffers little corrosion. In those instances

Chevron Corporation

3100-29

August 1999



where the columns have been corroded to their minimum allowable thickness as a result of many years’ service, either carbon steel or Type 405 stainless steel linings may be applied, depending on the level of corrosion rate encountered. However, in the newer crude units which process sour crudes at high temperatures, significant corrosion of carbon steel is anticipated in sidecut strippers operating over 600°F. For this reason, Type 405 or 410S steel cladding and internals have been used in the hottest sidecut strippers in our newest plants.

3162 Gasoline Rectifier Corrosion Since a large part of the hydrogen sulfide released from the crude will ultimately find its way into the light ends system, gasoline rectifier columns will often show the effect of wet hydrogen sulfide corrosion. While corrosion rates are usually not excessive, the corrosion products formed by reaction of hydrogen sulfide with steel are voluminous and often lead to plugging difficulties. The situation has been successfully remedied through the use of corrosion inhibitors which, due to their detergent action, tend to prevent the accumulation of excessive sulfide scale within the column. However, these flushed out deposits may collect in downstream equipment.

3163 Corrosion in Piping and Valves Corrosion problems in the furnace transfer lines and in the atmospheric and vacuum column overhead piping have been discussed previously. In general, corrosion in other process piping will be similar to that experienced in the equipment where the process fluid originates. For example, if a line comes from an alloy-clad column or vessel, it is generally necessary that the line be alloy. In plants processing sour crudes, hydrogen sulfide corrosion is likely to occur in carbon steel atmospheric column bottoms and sidecut lines operating above about 500°F. Over 700°F, the life of a steel line in these services may be little more than one year. For this reason, consider 5% Cr steel where temperatures exceed 500°F. Similarly, naphthenic acid corrosion is usually found in atmospheric and vacuum sidecut lines when this same type of corrosion is occurring in the column from which the line originates. Naphthenic acid corrosion of piping can be prevented through the use of Type 316L (> 2.5% Mo) or 317L stainless steel. Valve bodies are generally constructed of the same material as the piping in which they are located. The conventional 12% Cr steel valve trim is generally adequate where valve bodies are carbon steel or 5% Cr steel. For austenitic stainless steel valves, trim should be either a matching composition or Stellite. However, there are a few instances, such as in atmospheric column overhead systems or desalter effluent water, where a special valve trim such as Monel may prove desirable.

August 1999

3100-30

Chevron Corporation



3164 Corrosion in Pumps Due to high turbulence, considerably more corrosion may be encountered in pumps, particularly on the impellers, than in the associated piping systems. The general areas of usefulness of various alloys in crude unit process pumps are tabulated below. Cast iron

General material for pump impellers at temperatures below 450°F

Carbon steel

Pump cases and impellers where corrosion is not a serious factor

5% chrome steel and either 12% Cases and impellers, respectively, for handling chrome steel or CA6NM residuum and heavier sidecuts where corrosion is due to sulfur components Austenitic stainless steel

Vacuum column sidecut pumps when processing highly naphthenic crudes. Under such conditions, Type 317 steel is the preferred material.

Ni-resist

Shows a pronounced advantage in corrosion resistance over cast iron for impellers in atmospheric and vacuum overhead systems. Incremental cost is frequently quite low. Availability may be a problem.

3165 Desalter Corrosion Desalter vessels are typically carbon steel. They may have a heavy corrosion allowance or be protected against corrosion by a gunite (concrete) lining. Most of our earlier desalters were bare steel. It was found that they suffered from rapid pitting during the first few years of operation. As a result, it became the practice to gunite-line new desalters, initially the full vessel and later only the bottom 120 degrees. With the partial gunite lining, Monel flashing was used along the edge of the gunite to prevent undercutting. As the years progressed and the early unlined desalters remained in service, it became apparent that the deep pits formed during early operation were not growing with time, and the practice of gunite-lining new desalters was abandoned. Current practice is to construct new desalters of bare steel with a heavy (¼-inch) corrosion allowance.

3170 References

Chevron Corporation

1.

Piehl, R. L. “Correlation of Corrosion in a Crude Distillation Unit with the Chemistry of the Crudes,” Corrosion, Vol. 16 No. 6 (June, 1960), pp. 139–141.

2.

Ellis, J. R. B., and R. A. Farnham. “Design Recommendations Dilute Caustic Injection System for Crude Units,” Chevron Research and Technology

3100-31

August 1999



Company, May 8, 1978. Consult with Chevron Research and Technology Company for possible updated design recommendations.

August 1999

3.

Wanat, W. “Design Recommendations Aqueous Ammonia System Corrosion Control Crude Unit Overhead Systems,” Chevron Research and Technology Company, November 15, 1972. Consult with Chevron Research and Technology Company for possible updated design recommendations.

4.

Schmidt, P. C., and J. W. Skogsberg. “Crude Unit Overhead Erosion - Corrosion Richmond Crude Unit No. 4 Data Evaluation,” Chevron Research and Technology Company Report, Materials and Equipment Engineering File No. 75.16.56.02, January 6, 1978.

5.

Piehl, R. L. “Naphthenic Acid Corrosion in Crude Distillation Units,” Materials Performance, Vol. 27 No. 1 (January, 1988), pp. 37-43.

6.

Ploetz, J.C., “Naphthenic Acid Corrosion Guidelines,” Chevron Research and Technology Company Report, Materials and Equipment Engineering File No. 75.16.56, September 7, 1990.

7.

Shargay, C.A., “Naphthenic Acid Corrosion,” Chevron Research and Technology Company Report, Materials and Equipment Engineering File No. 16.20.55.02, May 25, 1983.

8.

“Crude Unit Best Practice Atmospheric Overhead Corrosion Control,” originally published on Lotus Notes, also Chevron Research and Technology Company, Materials and Equipment Engineering File No. 75.16.56.02, June 21, 1995.

3100-32

Chevron Corporation

Crude Distillation Units

Recommend Documents