An Overview of Oxygenates in Olefins Units

In Relation to Corrosion, Fouling,

Product Specifications, and Safety

by

George Nowowiej ski and

John A. Reid

of Stone & Webster Inc., A Shaw Group Company

Prepared for Presentation at

American Institute of Chemical Engineers

2003 Spring National Meeting New Orleans, LA

Copyright© Stone & Webster Inc., A Shaw Group Company March 31, 2003 "Unpublished"

AIChE shall not be responsible for statements or opinions in papers or printed in its publications.

DISCLAIMER OF RESPONSIBILITY

Neither Stone & Webster Inc., A Shaw Group Company nor any of the contributors to this document makes any warranty or representation (expressed or implied) with respect to the accuracy, completeness, or usefulness of the information contained in this document. Stone & Webster Inc., A Shaw Group Company assumes no responsibility for liability or damage which may result from the use of any of the information contained in this document.

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An Overview of Oxygenates in Olefins Units In Relation to Corrosion, Fouling, Product Specifications, and Safety

Abstract _ _

The focus of this paper and presentation is on greater understanding of corrosion and fouling issues within the olefins unit due to elemental oxygen and/or oxygen containing compounds. Organic acids within the quench water system and cracked gas compressor train are frequently secondary reaction products of CO and CO2 produced in the furnace cracking coil by steam-carbon water gas shift chemistry. Many of these acids promote olefin compound cross-linking reaction. Oxygen and/or sulfur containing compounds in ~ olefin unit feedstocks or vent recovery streams frequently increase downstream corrosion and fouling rates. A short summary of olefin unit corrosion and fouling experience will be presented with the related process chemistry to illustrate potential process design and operating issues.

Introduction

Trace amounts of oxygen and/or oxygen containing compounds have been reported to promote corrosion and/or fouling within olefins units and other process units.

Organic acids containing oxygen are well known corrosion issues in olef'm production units and refinery process units. Elemental oxygen in contact with butadiene or cracked gasoline is known to promote polymer or gum formation and increase the risk of process fouling.

A number of regenerative sulfur treating process designs use air injection. Two common sulfur treating processes, used for naphtha boiling range fractions, that add air are Bender Sweetening and Mercapfining.

During transportation or storage of liquid C5-plus cracking feed stocks contamination with elemental oxygen and/or oxygen containing compounds, such as, methanol, ethanol, MTBE and similar may occur. The entry of sea water or rain water or fiver water into liquid cracking feed stocks also allows entry of dissolved elemental oxygen.

A trace amount of elemental oxygen (02) is soluble in water and most hydrocarbons. Some oxygen containing compounds naturally occur in crude oil and to a lesser extent in oil field condensate. Elemental oxygen in cracking feeds or vent streams routed into the olefins unit for recovery section may also result in processing problems. The entry of cooling water into process equipment operating at low pressure is another common potential source elemental oxygen.

On-Specification Produc.~

Ethylene and propylene product specifications typically limit elemental oxygen content to less than 5

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ppmv, A few product specifications limit elemental oxygen content to less than 2 ppmv. During routine unit operation these oxygen limits are not an issue. Problems related to on-line and laboratory analysis for elemental oxygen content in ethylene and propylene product streams are frequently more an issue than oxygen being present.

Several olefms units have experienced off specification polymer grade propylene (PGP) due to trace amounts of methanol in the C3 Splitter feed. Methanol removal systems have been installed in some olefms unit to minimize the risk of off specification PGP.

Some of these methanol removal systems create new fouling and safety issues during routine operation. These fouling and safety issues will be discussed with methanol removal considerations in Appendix A and B.

Frequently a sales specification for crude mixed C4, butadiene, and/or mixed butenes will limit carbonyl and methanol content.

Feedstock Impurities Survey

Information reported in "Selected Ethylene Feedstock Impurities: Survey Data" (1) shows that eight producers routinely analyzed for methanol in feedstocks. Data published through the Gas Processors Association (GPA) titled "Trace Contaminants in Natural Gas Liquids" shows:

a. Methanol varied from: 1 to 50 ppm in the seven selected E/P mixes (2) and

14 to 258 ppm in the seven selected propane rich samples and 3 to 696 ppm in the 11 selected raw NGL rich samples.

bB Methanol in GPA "Natural Gasoline" was less than I ppm for five samples, and 78 ppm in one sample than contained 240 ppm of C5 olefms.

C. Acetone varied from: 1 to 12 ppm in seven selected iso-butane samples. 7 to 94 ppm in six selected n-butane samples.

dQ Testing of 11 NGL "raw make" samples showed oxygenates such as: methanol, acetone, and t-butanol.

Methanol - A Maior Oxygenate Issue

Methanol is sometimes present: a. E/P feedstocks, b. C4 raffinate returned from MTBE production, c. vent gas from some poly-propylene units.

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21 Methanol is also produced in the fia'naces by cracking MTBE or TAME present in feedstocks.

@ Methanol is sometimes added to olefins unit equipment operating at low temperature for dry-out prior to chill down or directly into the process as corrective action to remove hydrates or ice.

In the olefins unit cracking furnaces, somewhere from 50 to 75 percent of the feedstock methanol is typically converted into CO and water. High cracking temperatures and long residence time coils favor a high methanol conversion.

If methanol is received as a concentrated slug into the t in, aces, increased CO production may result in operating upsets of:

a=

b. C.

d.

Front-end acetylene reactors Hydrogen methanation systems Back-end acetylene reactor system using raw hydrogen as a CO source. Hydrogen PSA units being operated in a variable cycle mode for maximum hydrogen.

Oxygenate Compound Formation and Reactions

The presence of oxygenated compounds in olefins units based on gas only and liquid feed cracking has been documented. The presence of carbonyl compounds and specifically acetaldehyde in the cracked gas feed to caustic wash towers was presented in an EPC paper several years ago (21).

Oxygenated Compounds from Ethane and Oxygen

Extensive laboratory and small semi-scale test work has been done on the production of ethylene from auto-thermal dehydrogenation of ethane using oxygen. In the auto-thermal dehydrogenation process, the "heat of cracking" energy input is provided by ethane partial combustion. Secondary reaction by- products include: formic acid, acetic acid, and formaldehyde formed by ethane oxidation (17). High mole weight organic acids are also typically present in the quench water used for direct contact cracked gas cooling.

Thermal - Steam Cracking for Olefins

The "cracked gas" produced in an Olefins Unit by thermal cracking of ethane through C10+ hydrocarbons in the presence of steam contains several very reactive compounds. These reactive compounds include acetylene, butadiene, carbon monoxide, ethylene, hydrogen, methyl-acetylene, and styrene. Some oxygenates in cracking feedstocks will be converted into secondary products; but this conversion is frequently less than complete. Methanol conversion during co-cracking with E ~ feeds has been discussed at several EPC meetings in relationship to methanol contamination of product propylene. Methanol is also produced during cracking MTBE or TAME present in some feedstocks. Solvents such as acetonitdle (ACN) used for butadiene recovery will produce NH3 and HCN during cracking.

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CO and CO2 from Thermal Crocking Reactions

Carbon dioxide (CO2) and carbon monoxide (CO) are produced during hydrocarbon stream cracking due to steam reforming reactions. Sulfur compounds such as DMS, DMDS, or mercaptans will frequently be added to E~ and low sulfur recycle stream feeding the steam cracking furnaces to minimize CO and CO2 formation from reactive metals, such as nickel, used to manUfacture the cracking coil.

Carbonic Acid

Cracked gas cooling by direct water contact in the quench water tower results in CO2 being dissolved into the water with formation of carbonic acid. This may be shown as: CO2 + H20 --> H2CO3. The term carbonic relates to a -COOH group in a hydrocarbon chain. A carbonic acid (aliphatic acid) has the general form of R-COOH.

Common Chemical Names and Properties

Figure 1 shows names and chemical structures for one through four carbon alcohols and organic acids. Table 1 shows some common "carboxylic acid" names, chemical structure, and normal boiling points. The organic compounds described in this paper are of the following types:

a. Aliphatic acids: R-COOH b. Aromatic acids: Ar-COOH c. Naphthenic acids" X-COOH d. Phenols: R-Ar-OH

(where R is a straight or branched chain). (where Ar is a benzene ring or tings). (where X is a cyclo-paraffinic ring). (where Ar is a benzene ring, R is typically a straight or branched paraffin chain).

Light naphtha and raw pyrolysis gasoline boiling ranges are frequently between 90 and 375 degrees F. The following paraff~c acid compounds also boil between 90 and 375 degrees F; formic, acetic, propionic, n-butyric, and iso-butyric.

It has generally been concluded that the carboxylic acids in petroleum with fewer than eight carbon atoms per molecule are almost entirely aliphatic in nature; mono-cyclic acids begin at C6 and predominate above C I 4. This indicates that the structures of the carboxylic acids correspond with those of the hydrocarbons with which they are associated in the crude oil; that is, in the range in which p~s are the prevailing type of hydrocarbon, the aliphatic acids may be expected to predominate; similarly, in the ranges in which mono-cyclo-paraffins and di-cyclo-paraffins prevail, one may expect to find principally mono-cyclic and di-cyclic acids, respectively.

Organic Acids and W_ater pH Values

Table 2, shows the effect of 100 ppm of an acid on water pH, at 77 degrees F (14). Common organic acids with reduce water pH from neutral (7 pH) to about a 3.7 pH. Inorganic acids, such as sulfin'ic, hydro-chloric, or hydrofluoric acid are required to lower water pH below 3.

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Oxygenate Compound Formation

Many olefin units built between 1950 and 1965 used front-end, raw cracked gas hydrogenation reactors for acetylene (C2H2) reduction or near total removal. The hydrogenation catalyst used in these reactors was frequently nickel sulfide based or nickel in combination with cobalt. Many of these early hydrogenation reactors produced propionic acid and similar organic acids, through CO addition reactions.

One of the text book reactions for making propionic acid is:

C2H4 + H20 + CO ... . > CH3-CH2-COOH

Optimum reaction conditions given for the above reaction are 650 degrees F and over 10,000 psig with a nickel or similar metal surface. But, propionic acid has been found downstream and not upstream of wet raw gas acetylene reactors operating below 400 degrees F and less than 250 psig.

Oxygenate. ComPounds and Process Chemicals

Several solvents used for aromatic recovery units use process chemicals, such as ethylene glycol or sulfolane that contain oxygen. Some of the solvents used in butadiene recovery units contain oxygen. Recycle cracking of a raffinate from an aromatic or butadiene recovery unit may result in feeding a trace amount of oxygen to the olefm unit.

Ethylene glycol is used in many natural gas treating units to aid gross water removal. A trace of ethylene glycol may be present in the mixed ethane-propane product from some older LPG or NGL recovery units that do not use low temperature or cryogenic technology.

Ethylene glycol is sometimes used in DP insmanents as a seal fluid. A process upset or seal failure may result in ethylene glycol entering an olefins unit process stream.

The solvent MEK is used in some lube oil treating units. Heavy boiling material not suitable for lube oil production is sometimes sent to the steam cracking furnace in an olefins unit.

Isopropyl alcohol is used in some olefins units as a pump seal fluid, instead of methanol. A pump seal problem can therefore result in Isopropyl alcohol entering the process or loss to the environment.

Morpholine is a water treating chemical commonly used for pH adjustment. Morpholine contains both oxygen and nitrogen.

The chemical structure of these compounds is shown in Figure 5.

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Other Oxygenate Coml~unds

In addition to the carboxylic acids, alkaline extracts from petroleum contain phenols. Phenols (phenol, cresols, xylenols) may be present in cracked distillates from which they are sometimes isolated and sold. Aldehydes are also found in cracked distillates and are believed to be responsible for much of the gum formation. Alcohols, ketones, and other oxygenated compounds occur in oils oxidized at relatively high temperatures.

Acetone

A small number of olefins units use acetone as a solvent for recovery of acetylene or MAPD. Very few olefins units have reported acetone related operation issues.

A primary industrial method for production of acetone (2-propanone) is the dehydrogenation of isopropyl alcohol. Isopropyl alcohol normally made by the hydrolysis of propylene. Acetone is also made on a large scale as a co-product of making phenol from cumene. Cumene is produced on a large scale by alkylation of benzene with propylene.

Phenol Compounds

Phenols occur to an appreciable extent in crude oil and in the appropriate fractions of refinery products. The commercial mixtures of higher boiling phenolic materials are called cresylic acids from a predominance of the cresol compounds. The chemical structures for Phenol and major cresol compounds are shown in Figure 4.

Tertiary-butyl,alcohol

An industrial method for making Tertiary-butyl-alcohol (TBA or t-butyl-alcohol is the hydrolysis of iso- butene. Iso-butene is the primary product oft-butyl-alcohol dehydrogenation.

Organic Acids Produced by Fermentation

Some of the minor products of sugar fermentation include the following compounds (29): Formic Acid Propionic Acid Ethyl Butyrate Acetic Acid Butyric Acid Ethyl Acetate

The above compounds are also found in:

ao

b. hydrocarbons flowing from oil and/or gas wells, and olefm unit quench water and raw gasoline.

Natural sugar compounds are produced extensively by plants as a biological energy conversion and storage method. Some plant fi~tit, for example grapes, is used to make wine. Fermentation of carbohydrates and

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starch produced by plants (for example, corn, rice, and wheat) are used to made ethanol and secondary compounds that are distilled to make drinking alcohol products.

The two primary products of fermentation are ethyl alcohol and carbon dioxide. Early work by Lavoisier (1789) expressed the following the formulation:

ao

b. Hexose to Ethyl Alcohol and Carbon Dioxide, or C6H1206-> 2C2H5OH + 2CO2

Pasteur (1857) reported that this formulation accounts only for about 95% of the sugar comurned. Glycerin, organic acids and traces of other by-products account for the balance. These other by-products, are now known to include 5 fusel oil (higher alcohols), some acetaldehyde and other aldehydes and some esters.

Pasteur report the actual yield from the fermentation of 100 pounds of sugar was as follows (29):

Compound Pounds Alcohol 48.55. Carbon 46.74. Glycerol 3.23 Organic Acids 0.62 Miscellaneous 1.23 Total 100.37

The total weight of fermentation products exceeds slightly the weight of sugar fermented is explained by the absorption and fixation of small amounts of water to make certain of the by-products. According to Pasteur some sugar is also utilized by the yeasts in building new yeast cells.

Oxygenated Compounds in Petroleum

Oxygenated compounds found in petroleum or its distilled products may be present in the crude oil, or they may be formed in the distillation or in contacting oils with atmospheric oxygen. In crude petroleum the "total" quantity of oxygen seldom exceeds 0.5 per cent (22).

Higher mole weight and higher boiling temperature fraction of crude oil typically contain more oxygen than lighter fractions. Some heavy fuel oils (bunker C) are reported to contain 5 to 6.5 percent elemental oxygen (22).

Figure 6, is a based on IFP information showing an increasing oxygen content with boiling fraction until the sample specific gravity is above about 0.95. The shape this oxygen curve is similar in shape to sulfur content data versus sample specific gravity. Boiling fractions with a specific gravity approaching 1.0 have typically been processed at high temperatures during distillation, cracking, or coking units. During high temperature processing some weaker chemical bonds are broken resulting in the formation of some

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lower mole weight fragments rich in oxygen and sulfur and formation of higher mole weight compounds with more carbon to carbon bonding.

In general, petroleum or its products may contain various types of acids, aldehydes, aleoh01s, or phenols, as well as compounds of as yet undetermined chemical structure. Acids are the most important of these constituents of the oil, and as a rule, they are naphthenie or poly-naphthenic in type. Only small quantities of fatty acids are present in crude oil, such as formic, acetic, isoaniyl-aeetie, diethyipropionie, or other low-boiling members of the series. However, some crude oils contain some high molecular weight fatty acids, such as palmitic, stearie, myristie, and araehidic.

Naphthenic acids, are by far the most important oxygenated compounds found in the crude petroleum. These acids are frequently isolated from the oil during refining operations and used for manufacturing by-products, such as soaps.

Oils containing these acids are corrosive to distillation equipment and may have undesirable characteristics after they are refined unless the acids are completely removed. Crude oils rich in naphthenie acids are usually of naphthenie type, such as those of the Gulf Coast or of California.

The oxygenated compounds in petroleum oils are usually eliminated in the course of refining. They are easily attacked during hydrotreating, or by sulfuric acid, solvents, clay treater, and particularly by solutions of alkali. In exceptional cases, however, their removal presents a serious difficulty and may require certain changes in the scheme of refining.

Naphthenic Acids

The presence of acid substances in petroleum first appears to have been reported in 1874. It was established 9 years later that these substances contained earboxyl groups and were earboxylie acids. These were termed naphthenic acids. Although alieyelie (naphthenic) acids appear to be the more prevalent, it is now well known that aliphatie acids are also present.

The naphthenie acids of commerce interest are a mixture having a molecular weight range of 180 to 350. They are dark in color and have an unpleasant odor. They are principally used in the form of their metal salts. The lead, cobalt, and manganese salts are used as paint driers, and lead naphthenates are also components of extreme pres sure lubricants. Other salts are used in greases and to jelly gasoline.

Butadiene Reactions and Fouling

Butadiene is a reactive compound and is frequently a fouling issue in olefin units. During storage "pure" butadiene will slowly react (dimerazation) to make 1-vinyl-3-eyelo-hexene. This dimerization of two butadiene molecules to make a C8 compound occurs in both the liquid and vapor phase. Table 6 shows that the butadiene dimerization rate is strongly a function of temperature. The butadiene dimerization reaction rate is reported not to be catalyzed by peroxides or by steel surfaces.

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The dimer, 1-vinyl-3-cyclo-hexene, is miscible with butadiene at normal process temperatures. Conventional distillation is commonly used to separate butadiene from the dimer. The boiling temperature of butadiene is -4.4 degrees C, at 760 mm of mercury versus a dimer boiling temperature of 127 degrees C.

Butadiene in contact with air will form peroxides. These peroxide compounds promote long chain polymer formation to produce plastic or rubber like materials. Table 7 shows butadiene polymer formation rate as a function of oxygen concentration. Table 8 shows butadiene polymer formation rate as a function of temperature for a constant oxygen concentration.

Butadiene Peroxides

Butadiene on contact with air forms peroxides quite readily. Peroxide formation can be prevented by the exclusion of air or by the use of inhibitors, such as tertiary-butyl-catechol (TBC), hydroquinone, di- n-butylamine, phenyl-a-naphthylamine, phenyl-bunaphthylamine or aqueous sodium nitrite. Inhibitors protect only the liquid butadiene in which they are dissolved. Peroxide may be destroyed by heating butadiene with alkali, or ferrous salts.

Highly diluted solutions of peroxides are quite stable. When concentrated at elevated temperature, they become dangerous because of their tendency to decompose violently. This may be overcome, especially in batch distillation, by dilution with high-boiling liquid hydrocarbons.

Butadiene, free of inhibitor, may be obtained by distillation. TBC (Tertiary-Butyl-Catechol) may also be removed by caustic washing. Solid butadiene absorbs enough oxygen at a sub-atmospheric pressure to make it detonate violently upon slight heating above its melting point.

The peroxide in butadiene formed from contact with air promotes the formation of polymers in storage. The formation of plastic polymers depends upon the peroxide content and temperature.

Butadiene "Popcorn" Polymer

The "plastic type" polymers are not soluble in butadiene. They may separate out and be troublesome in many operations. Their formation can be minimized by maintaining minimum temperature, by avoiding contact with oxygen and by the use of inhibitors.

The formation of "popcorn" polymer is initiated by peroxide or air. Rusty iron and water will cause it to form even in the absence of air. When it is formed, it will grow slowly either in the presence or absence of air and in contact with liquid or gaseous butadiene. The usual inhibitors do not prevent the growth of "popcorn" but will probably inhibit its formation provided no seeds of this polymer are present.

Aqueous sodium nitrite has been proposed and effectively used as a control agent for "popcorn" polymer. "Popcorn" may be deactivated with NO2 or N203 gas. One way to remove "popcorn" polymer is by soaking with a dilute solution of caustic soda or sodium bisulfite.

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Butadiene Thermal Polymer and Fouling

Butadiene is a highly reactive molecule and will form dimer and higher mole weight compounds during storage, without a catalyst being present. If oxygen or a metal oxide catalyst is present the butadiene polymer formation rate will be greater than a sample in an inert container at the same temperature.

Butadiene ,F, ou!ing and Dcpropanizer Design

Butadiene related fouling frequently occurs in both front-end and back-end flow sheet concepts used for olefms units. Frequently this fouling is related to time at temperature for butadiene and similar materials being processed. Many olefin units have spare depropanizer reboilers to allow a 3 to 5 year on-line plant cycle with a reboiler cycle time 6 to 18 months.

Depropanizer fouling is typically greatest within the reboiler. If process anti-fouling chemicals are not used, after 1 to 2 years fouling of the lower trays in the depropanizer will sometimes limit the olefin unit C4 plus processing capacity.

A few olefin units have been built with both spare reboilers and spare tower bottom sections to maximize the olefin unit on-line cycle. In some units, the cost of this spare tower section is sometimes off-set by a reduced need for process anti-fouling chemicals.

Using a process design that lowers the depropanizer reboiler temperature by lowing the tower operating pressure is one of the classic methods to decrease tray and reboiler fouling. Using propylene refrigeration instead of cooling water for the depropanizer condenser results in a higher energy usage and frequently a higher related operating cost.

A dual pressure (tower) depropanizer is another option to lower the depropanizer reboiler temperature by lowing the tower operating pressure while still using cooling water for bulk heat removal. Stone & Webster's US patent number 3,783,126 illustrates this process design for a classic back-end depropanizer design.

A dual pressure front-end depropanizer system has been utilized on several recent Stone & Webster process designs. Figure 10, illustrates one version of this dual tower concept with both a high and lower pressure

and LP) tower system used to make 3 streams.

Figure 10 shows both a dual pressure depropanizer concept and an application of distributed distillation. The high pressure (HP) depropanizer is designed to make a split between ethane and butadiene. In this design C3 compounds are allowed to go into both overhead and bottom streams from the HP depropanizer.

The low pressure (LP) dcpropanizer is fed by the bottoms of the HP depropanizer and finishes the separation between C3 and C4 plus compounds. To minimize the reboiler operating temperature, the warmest level of propylene refrigerant is normally utilized in the overhead condenser thereby reducing the tower system operating pressure and the bottoms temperature.

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The C3 product drawn from the LP depropanizer tower overheads is pumped to the C3 hydrogenation unit thus completely bypassing the demethanizer and the deethanizer system. This design greatly reduces the potential for fouling in the deethanizer. The operating temperatures and thus the pressure of deethanizer can now be adjusted consistent with available refrigerant levels without regard to fouling considerations. Removal of heavy ends (C4+) upstream of the deethanizer typically results in colder reboiler inlet temperatures than in traditional designs. This typically allows use of quench water heat for the deethanizer reboiler with a reasonable sized heat exchanger and LMTD.

.Quench Oil Composition and Fouling

High temperature thermal cracking of naphtha or gas oil makes some compounds can react to form polymefized products. Compounds that have both an olefin and aromatic nature, such a styrene, have a faster polymerization rate than an pure olefm or aromatic compound. These polymerized products normally have a higher specific gravity and viscosity than the compounds that they were produced from. The rate of polymer formation increases greatly with tempemttae.

Compounds such as carbonlys and sulfur in the naphtha or gas oil feeds may increase the rate of quench oil polymer formation. A naphtha feed rich in aromatic and naphthenie type compounds will produce more fuel oil and more compounds that can form polymers in the quench oil than a naphtha rich in light paraffinic compounds.

As the boiling point of aromatic compounds increases so does the viscosity and density. Highly poly- aromatic compounds, (commonly used for asphalt) that are solids in a pure state at ambient temperature can be dissolved in the lighter aromatic compounds present in quench oil and RPG. Removing light aromatic compounds by boiling this quench oil will result in the concentration of heavy ends into tar or solid residue depending on the amount of heat used.

Adding low viscosity RPG or imported oil to high viscosity quench oil will reduce the quench oil mixture viscosity. Mixing equal amounts of high and low viscosity oil will not result in an oil mixture with the average of the two oil viscosities. The oil mixture will have a higher viscosity than the calculated average.

It is critical to remember that operating the Quench Oil Tower at a high bottoms temperature results in a higher oil viscosity by the combination of stripping lighter compounds from the oil and a higher rate of polymer formation.

Figure 7, shows a high temperature oil quench system with two fuel oil strippers. Producing both a light and heavy fuel oil product (LFO and HFO) allow more control of the quench oil viscosity and boiling curve than using one stripper to make a fuel oil purge stream.

The HFO stripper is operated to purge the higher mole weight compounds from the circulating quench oil. The LFO stripper is frequently operated to purge the C9 to C 12 compounds from the circulating quench oil and gasoline reflux produced in the water quench system. Removing C9 plus compounds through the fuel oil system reduces the amount of "heavy-ends" in the pyrolysis gasoline hydrotreater feed. Reducing these heavy-ends normally results in a longer hydrotreater on-line cycle.

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Gasoline Hydrogenation Reactor Foulin~ = .

During raw gasoline processing, dissolved oxygen is a major cause of gum (polymer) fouling. Preventive measures practiced by olef'm units and refiners are gas-blanketing feed tanks, use of floating-roof tanks, direct rundown of feedstocks from process unit to unit, instead of always through day tanks, and use of antifoulants. These methods help minimize polymer deposits but seldom eliminate them.

The first stage "Gasoline Hydrogenation Reactor" in an olef'ms unit may experience both physical fouling and catalyst fouling. Carbon laydown, or coking, of the catalyst covers active sites, so temperatures must be raised. Coking during normal unit operation is a gradual process. Sudden coking of catalyst can be a result of loss of hydrogen or of inclusion of large amounts of high-boiling hydrocarbons in the feed.

Hydrogenation Reactor Feed Heater Fouling

The second stage "Gasoline Hydrogenation Reactor" in an olefins unit may require use of a high temperature steam heater or fh'ed furnace for reactor feed temperature control.

Many of these second stage hydrogenation reactors operate in the vapor phase. In the reactor feed heater, a gasoline and oil mixture will be passing through the "dry point", at which the feed becomes completely vaporized.

This final vaporization zone is where deposits (fouling) frequently occur. Deposits in heat exchanger or fired heater tubes reduce heat transfer rate. The high tube skin temperature necessary to compensate for loss of heat transfer rate. A local hot zone in a fired heater may lead to tube failure and fire with the reactor feed entering the heater firebox. Some olefins units and/or refiners make certain the feed is completely vaporized by heat exchange before the feed enters the fired heater. This moves the deposits from the heater to the shell and tube heat exchangers.

One refinery HDS unit that suffered repeated heaterombe failures solved this problem by deoiling the naphtha, thus removing a high-boiling polymer-forming material before the HDS unit.

The boiling range of the "wash oil" injected into the cracked gas compressor may have a large effect on the boiling curve of gasoline and oil mixture going to the first and second stage hydrogenation reactors. Figure 8, shows a common cracked gas compressor with heavy gasoline exiting through a "distillate stripper". Some organic acids present in the cracked gas system will also exit through the "distillate stripper" and flow into the first stage gasoline hydrogenation reactor system.

Organic acid related corrosion in a depentanizer located between the first and second stage gasoline hydrotreating reactors is discussed in Appendix C.

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Silica

Silica is a name commonly applied to silicon dioxide (SiO2). Quartz crystals are an example of high purity silicon dioxide that occurs in nature. ~ Sand and sandstone are largely composed of silicon dioxide. Many clay materials contain a combination of aluminum oxides and silicon oxides.

A common silica source is antifoam carried in cok~r naphtha. Another silica source is antifoam used in fractionators. The poly-siloxane antifoam agent breaks down on contact and deposits silica on the catalyst (23).

A suggested remedy is to reduce the amount of antifoam used in cokers and fractionators. Another suggested remedy is the use on top of the catalyst bed of support balls containing a low concentration of nickel-moly. The activity imparted to the support balls facilitates anti-foam-agent breakdown and deposits silica on the support instead of on the catalyst.

Silica is only one of many materials known to foul the top of the catalyst bed in HDS reactors. Catalyst fines, scale, coke, polymer, and caustic are some materials that deposit in the top layer of the catalyst. They result in poor flow distribution and an increase in pressure differential across the reactor. The fouling can be either blockage by fines in spaces between catalyst particles or crusting of the top layer of catalyst.

After a time, the reactor must be opened and the top layer of the catalyst bed removed by skimming. Since skimming requires entry into the top of the reactor, inert entry must be made under a nitrogen atmosphere. The catalyst is broken up and vacuumed off to remove the crusted layer. Polymers are deposited, not only on top of the catalyst but also in the exchangers and in the feed heater tubes.

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Appendix A Methanol Considerations

MTBE and Methanol

O l e ~ units sometimes crack C4 streams that have been previously processed through units making MTBE (Methyl Tertiary-Butyl Ether). If trace amounts of MTBE are present in the olefins unit cracking feedstock it will be converted to CO and methanol.

Ships or storage tanks previous used for motor gasoline containing MTBE or similar materials are sometimes used in naphtha service without cleaning. Several olefins units have been surprised with varying amounts of MTBE or similar materials in cracking feedstocks.

MTBE is produced by reacting iso-butene (present in a mixed C4 stream) with methanol over a fixed bed of catalyst. The MTBE synthesis reaction is an equilibrium reaction which highly favors MTBE production at moderate temperatures. An Iso-butylene conversions of 96%-97% is commonly obtained using a single pass reactor.

During MTBE production secondary by-products formation is normally minimal, but is a source of trace compounds. Tertiary butyl alcohol (TBA) is formed from hydration with the water content of the feed. Dimerization of isobutylene produces di-iso-butylene (DIB). DIB make increases as the ratio of methanol to isobutylene drops to or below the stoichiometric value. Some dimethyl ether (DME) is also formed from methanol dimerization.

Depending upon the MTBE process design used, varying amounts of methanol will be present in mixed C4 stream exiting the MTBE unit. During MTBE production, a slight excess of methanol is used to ensure maximum isobutylene conversion and to limit DME production. This excess methanol may be recovered by a water wash or mole sieve adsorption. Water wash systems are less expensive to build and are generally used.

TAME and Methanol

Olefins units sometimes recycle crack C5 olefin rich streams that have been previously processed through units making TAME (Tertiary-Amyl-Ether). TAME is produced by reacting iso-pentene (present in a mixed C5 olefins stream) with methanol.

MTBE and TAME as Nap,h,.tha Feedstock Contaminants

Barges, lines and/or storage tanks used for naphtha feedstocks may previously have been used in product motor gasoline service or blend product service. Compounds such as MTBE and TAME are added to gasoline to increase the octane value and provide a moderately cleaner combustion by adding oxygen. In the olefins unit cracking fiarnaces MTBE and TAME are converted to olefins, CO, and methanol.

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Mixed C4 Purification

One method for making "high-purity iso-butene" is by making MTBE from a mixed C4 steam using methanol,then MTBE isolation, followed by MTBE cracking to make iso-butene and minor amounts of DME, TBA, and dimers.

Methanol within an Olefins Unit

Within the olefins unit, methanol will concentrate in the C3/C4 streams. Methanol entering a C3 Splitter, producing a PGP product, will over an extended time period exit with both the PGP and C3 recycle. In the C3 Splitter, methanol will concentrate just as MAC/PD will concentrate 15 to 30 trays above the reboiler. Methanol tends to concentrate in the C3 Splitter where the 90 to 95 percent propylene zone exists. If methanol levels in the C3 Splitter build up over time, a minor upset or change in operating conditions may result in 10 to 50 ppmv of methanol at the PGP product draw from the C3 Splitter.

180

Appendix B

Methanol Reduction and Removal Issues

MTBE Removal with Water Washin~

The solubility of MTBE in water is about 4 weight percent at 20 degrees C or 68 degrees F. Water washing is therefore, an option for reducing the MTBE level in naphtha. If an MTBE problem is limited to one feed tank, then MTBE contaminated feed may be frequently used at a low rate to minimize olef'ms unit CO related problems and the moun t of methanol in the propylene system.

Methanol Bulk Removal with Water Washing

Gross mounts of methanol, over 250 ppmv, present in C4 raffinate returned from an MTBE unit are best reduced by water washing. This washing may be single or multiple depending upon waste water treating issues. The wash water used should be clean cold steam condensate or cold BFW. Wash water with a low TDS (Total Dissolved Solids) value is critical if the C4 raffinate will be vaporized in the cracking furnace convection section.

If C4 feedstocks are vaporized upstream of the furnaces, then equipment fouling judgements will determine water quality requirements. Trace amounts of water in a C4 cracking feedstock should not be a serious issue. Liquid water collection flow transmitter tubing does have the potential to cause furnace flow meter errors.

Methanol- Trace Removal

Methanol at low levels (less than 50 ppmw) is typically removed from either the PGP product or the C3 Splitter feed using molecular sieve or activated alumina products. Large pore molecular sieves such as 4A, 5A and 13X will adsorb methanol when not operated to water breakthrough. Methanol on a 4A or 5A sieve will be displaced by water and enter the E ~ furnace feed if the pipeline feed dryer is operated to water breakthrough.

Methanol Removal - Molecular Sieve Products

Some molecular sieve products may produce propylene dimers and higher order polymers (green oil) during regeneration. The 4A sieve obtained from different vendors may vary greatly in the amount of green oil formation. Some of this green oil will be flushed from the sieve and enter the flowing PGP product or C3 Splitter feed stream. Vendor references for this sieve application should be checked prior to bid list development. UOP markets an OG-491 sieve specifically for methanol from "reactive hydrocarbons" such as propylene. Other vendors can supply a suitable sieve that is less reactive than the generic 4A used for natural gas water removal.

181

The choice of molecular sieve or activated alumina products will depend upon the amount of methanol to be removed and the regeneration gas temperature available. Optimum bed loads and regeneration energy efficiency are obtained with a lead and guard bed operating mode for both molecular sieve or activated alumina products.

Methanol Removal - Activated Alumina Products

Activated alumina products that require regeneration gas temperatures of 500 to 550 degrees F have the highest methanol removal capacity in terms of pounds per 1000 pounds of active bed material. Both molecular sieve or activated alumina products are available that will operate with a regeneration gas temperature of about 425 degrees F, but a regeneration gas temperature of 500 to 550 degrees F is preferred for both 4A molecular sieve or activated alumina products. Alcoa's general purpose 'F-200' is a good product for both methanol and water removal if regeneration gas is only available at 400 degrees F. While it is possible to regenerate 'F-200' using tail gas at 400 degrees F the methanol removal capacity is less than other products.

Alcoa°s 'Selexsorb CD' is a promoted activated alumina product good for methanol removal. The 'Selexsorb CD' product will pick up about 2.2 weight percent methanol on a routine basis with a regeneration gas temperature of 450 degrees F. Alcoa's 'Selexsorb COS' product will pick up less than 1.5 weight percent methanol. But with 'Selexsorb COS' both COS and methanol may be removed. A major advantage of using 'Selexsorb COS' is that methanol and COS do not compete for the same active adsorption sites, since methanol is physisorbed and COS is chemisorbed. Layers or beds of 'Selexsorb CD' and 'Selexsorb COS' may also be used in a single vessel to optimize COS and methanol loadings.

Methanol Removal Location

The advantage of doing PGP product treating is a reduced flow rate and methanol load. The disadvantages of PGP treating includes the risk of CO from regeneration gases and green oil produced during regeneration entering the PGP product. Methanol removal from the C3 Splitter feed has the advantage that the methanol will not concentrate in the C3 Splitter to produce a surprise slug that may over load a PGP product treating system. Also if CO or green oil enter the C3 Splitter, they will not concentrate in the PGP.

The olefins unit tail gas used for bed regeneration is typically rich in CO. During bed cool down with a CO rich gas some CO may be adsorbed on the molecular sieve binder. Once the treater is on-line, trace amounts of CO can bleed into the flowing liquid C3 stream. A very high percentage of the CO entering the C3 Splitter will exit with the reflux drum vent stream with H2 and CH4. Therefore CO in PGP is only a problem when a level of less than 2 ppmv is required.

182

Appendix C

Corrosion in a Depentanizer Located Between the First and Second Stage Gasoline Hydrotreating Reactors

Summary

Severe, localized weld metal corrosion in the heat affected zone (HAZ) was observed in portions of an olefin plant Depentanizer in December, 1988. Investigation indicates that the likely cause is aqueous sulfide corrosion is the responsible corrosion mechanism. Although organic acid corrosion could not be ruled out.

Age and Design

The Depentanizer tower was made of carbon steel. This tower was apparently eight years old and had not been originally stress-relieved. As a result of localized corrosion in the upper section, this tower was cut and a new upper section of carbon steel was welded onto the existing tower. The new section was stress-relieved prior to placing the tower back into operation.

Inspection

Internal examination of the Depentanizer tower revealed severe preferential weld metal (HAZ) corrosion in upper areas of this vessel. It is believed that this was the first internal inspection of the tower. This tower had been in intermittent service for approximately eight years. The carbon steel tower is approximately 110 feet high and operates at a design temperature and pressure of 190 degrees F and 60 psig at the top and 325 degrees F and 70 psig at the bottom. There are 50 trays in this tower. Vessel trays and hardware (valves) were not corroded. These were reportedly Type 410 stainless steel.

Vessel wall sections, internal attachments, and welds were submitted to a testing laboratory. All testing confirmed metal to be carbon steel. All components were examined for possible sulfide stress-corrosion cracking. No such cracking was observed following visual examination or wet fluorescent magnetic particle testing of selected areas.

Corrosion Theory

Carbon steel that has not been stress-relieved can become susceptible to accelerated corrosion around welds (HAZ) and other areas of high residual stress when exposed to acidic media. The pH of deposits found in corroded areas inside the tower were all acidic indicating a low pH corrosion mechanism. Aqueous sulfide and/or weak organic acids could both promote the type of corrosion witnessed. The presence of corrosion at the top of the tower versus the bottom of the tower was believed to be a function of temperature profile. In this tower liquid water could be present at the top tower section as a result of a wet feed stream from tankage or small reboiler steam leak.

183

This unit's pyrolysis gasoline and quench water was shown to contain small amounts of organic acid (eg. Acetic acid, butyric acid, propionic acid, etc). A sampling program showed that the Raw Pyrolysis Gasoline (RPG) contained:

Concentration Compound micro-grams/ml Formic acid 35.4 Acetic acid 63.7 propionic acid 659 (approx.) pentanoic acid 1189 (approx.)

The specific form or forms of the propioni¢ and pentanoic acids were not determined. The concentration of the propionic and pentanoic acids is approximate due to use of a different test method and reference standard.

184

Appendix D

Pyrophoric Polymer in Deethanizer and De prgpanizer Colmnm

Naphtha and petroleum distillates are used as raw materials in the production of ethylene by pyrolysis. The rapid build-up of pyrophoric polymer in the deethanizer and depropanizer distillation columns can result in costly, unscheduled shutdowns in ethylene production due to plugging of equipment.

These shut-downs can last for weeks or months. This article briefly describes the work done to identify and study the polymer formed, and to find methods for reducing its rate of formation. A more complete account of the work can be found in the original article: "Rapid Build-up of a Pyrophoric Polymer in Ethylene Plant Deethanizer and Depropanizer Columns", The Canadian Journal of Chemical Engineering, Vol 32, June 1984.

The gaseous products from the pyrolysis of the naphtha or petroleum distillates feed stock in the furnaces pass through a series of distillation columns. Methane, hydrogen and carbon monoxide are taken off overhead from the demethanizer, while the bottoms go to the deethanizer. Ethylene, ethane, and acetylene are recovered overhead from the deethanizer while C3's and heavier compounds are removed as bottoms and fed to the depropanizer. Propylene, propane, methyl acetylene and propadiene are distilled overhead from the depropanizer while C4's and heavier compounds are drawn off as bottoms and sent to the debutanizer.

A mixture of butenes and butadiene is distilled overhead in the debutanizer while raw pyrolysis gasoline is drawn off as bottoms. The heaviest polymer build-up has been experienced in the depropanizer and, to a lesser extent, in the deethanizer.

Polymer Composition.., and Formation

Six sets of polymer samples were taken from the deethanizer and depropanizer. They were preserved by storage in glass jars filled with freshly boiled-out and cooled distilled water. Some exposure to air during sampling was unavoidable.

Less than 40% of the polymer was soluble in chloroform. Infrared spectra of the chloroform soluble material from both columns indicated that the main components were trans-l,4-polybutadiene and 1,2-polybutadiene. Low concentrations of terminal acetylene groups were also detected.

Absorptions at 730 cm-1 (cis CH deformation) were too weak to establish the presence of significant concentrations of cis-l,4-polybutadiene. There was no indication of the presence of polypropadiene, polypropylene or polybutene. Nuclear magnetic resonance (NMR) spectra of the carbon tetrachloride soluble portion of the polymer were similar to published spectra for polybutadiene produced by free radical initiated polymerization.

185

Both the IR and NMR Spectra indicated that the trans-l,4 form of polybutadiene predominated over the 1,2- form. The spectra also indicated the presence of less abundant components.

Untreated, fresh samples of polymer ignited on exposure to air. After several days, none of the samples collected were pyrophoric at less than 65-70 degrees C. Attempts to detect free radicals by electron spin resonance on month-old samples were unsuccessful. Iodo-metric titration to determine peroxide content were unsuccessful. This may be due to low solubility of samples, however other investigators have been unable to detect peroxides in synthesized polymers.

These observations do not preclude the presence of peroxides. The presence of small quantities of oxidation products (carbon monoxide, acetic and propionic acids, aromatic carbonyl compounds) indicate that some oxygen enters the plant system. It is known that butadiene reacts with air to form polymeric peroxides and that these are sensitive to heat and shock. Free radicals formed by decomposition of butadiene peroxides are likely initiators of polymer formation.

Thermogravimetric (TGA) and differential thermal analysis (DTA) were carried out in nitrogen and in air. Commercial Taktene 1220 polybutadiene (high cis-l,4 form) was also analyzed as a reference. The polymer samples from this study decomposed more rapidly in nitrogen than Taktene, and absorbed oxygen more rapidly and at a lower temperature.

Since metals are known to catalyze polymerization, samples from various points in the process during both normal and rapid polymer build up were burned into an ash and analyzed for metals. Iron was the chief component of the ash samples. A consistent relationship between metal concentrations and rate of polymer build up could not be determined. Some popcorn-like polymer, whose formation is promoted by iron, was observed in some areas. This is likely due to iron rust promoted polymerization.

Deactivation of pyrophodc polymer in plants

A range of deactivants were tested for their ability to decrease the oxygen absorption capacity, increase the thermal stability and increase ignition temperature of the samples by destroying peroxide or other groups on the polymer. Of the deactivants tested, sodium hydroxide was found to be the most effective.

When build up of polymer becomes suf~ciently great to necessitate a shut down of the deethanizer and depropanizer, the following steps are taken to increase periods between forced shut downs to more than one year:

• The columns are drained and depressurized to flare • Columns are then filled with water, drained and deactivated with a 2 to 3 % sodium hydroxide

solution. The solution is circulated through the column for several hours to deactivate the polymer. • The excess sodium hydroxide is neutralized with hydrochloric acid to pH 7 and the column drained. • Air is drawn into the column and the trays removed. • The trays and column surfaces are cleaned using brushes and sand-blasted to remove all polymer and

rust. During cleaning the polymer is kept wet to prevent possible auto-ignition of any deposit which may have been in contact with the sodium hydroxide solution.

186

• The trays are replaced and all surfaces pacified by circulating an agent such as sodium nitrite for several hours. This is necessary because the fresh metallic surfaces formed by mechanical cleaning have increased surface area and catalytic activity.

• The pacifying solution is drained off. • Oxygen free boiler water is added to the top of the column to wash the equipment and drained off

with the introduction of nitrogen to exclude air. • The column is pressure purged with nitrogen until the oxygen content is sufficiently low. • The column is then ready to go onstream.

Table 1

Physical Properties of Common Carboxylic Acids

Acid Structure formic acetic propionic n-butyric isobutyrie palmitie stearic vinylacetic benzoic

HCO2H CH3CO2H CH3CH2CO2H CH3CH2CH2CO2H (CH3)2CHCO2H2020 CH3(CH2)14CO2H CH3(CH2)16CO2HO CH2=CHCH2COaH C6H5CO2H

phenylacetic C6H5CH2CO2H

Boiling Pt. Deg C Deg F 100.7 213.3 118.1 244.6 141.1 286. 165.5 241.7 154.5 310.1 390. 734. 360. 680. 163. 325.4 249. 480.2 265. 609.

Table 2

Effect of Acids on Pure Water pH

Acid oH Formic 3.9 Acetic 4.2 Propionic 4.4 Butanoic 3.8 Sulfuric 3.0

Notes: The data shown above is at 77 degrees F. The acid content is 100 ppm (14).

187

Table 3

Naphthenie Acids Content in Various American Crude Oil Fractions

Crude Oil Type Naphthenic

Fraction acid (%)

Pennsylvania Paraftinic Pennsylvania Paraffinic East Texas Intermediate Texas heavy Naphthenie Midcontinent Intermediate

California Naphthenic

Kerosene 0.006 Gas oil 0.010 Kerosene 0.009 Gas oil 0.35 Kerosene 0.009 Naphtha 0.01 Kerosene 0.06 Gas oil 0.36

Table 4

Effect of Bases on Pure Water pH

Chemical ........... pH

NaOH 12.0 MEA 10.4 DEA 10.2 Cyelohexylamine 10.3 Morpholine 9.2 Ammonia 7.4

Notes: The data shown above is at 77 degrees F The acid content is 100 ppm (I 4).

Table 5

Boiling Points of Pure Amines & Treating Chemicals

Chemical Deg F MEA 339 DEA 515 Cyclohexylamine 274 Morpholine 263 Ammonia -28

188

Table 6

Effect of Temperature on Butadiene Formation Dimer Rate

Temperature Deg C Deg F

20 68 40 104 60 140 80 176 100 212

% Butadiene polymerized

Per hour 0.00015 0.0014 0.013 0.12 1.1

Table 7

Effect of Peroxide on Rate of Plastic

Polymer Formation at 45 Deg C

Active % Butadiene Oxygen polymerized ppm. Per hour 0 0.00 25 0.0040 100 0.0076 225 0.00120 400 0.0165

,

625 0.0200 900 0.0240 1600 0.0320

Table 8

Effect of Temperature on Rate of Plastic Polymer Formation

at 1200 ppm of Active Oxygen

Temperature % Butadiene Deg C Deg F polymerized

Per hour 20 68 0.0012 40 104 0.014 60 140 0.17 80 176 1.9

189

References

Q "Ethylene Producers Committee - Feedstock Issues Subcommittee Questionnaire Survey Data: Selected Ethylene Feedstock Impurities" by Mark A. Graham of Chevron Chemical Company. Presented at the Spring National Meeting, 1993,

11, "A Survey of Trace Contaminants in Natm~ Gas Liquids" by S. M. Wharry and N. J. Sung of Phillips Petroleum Co., Bartlesville, Oklahoma; Published in the Proceedings of the Seventy-Fourth GPA Annual Convention and in GPA TP-21.

Q GPA Technical Publication TP-21; "Trace Contaminants in Naatml Gas Liquids" from GPA Technical Section C, July 24, 1996

Q D. R. McPhaul and J. A. Reid, "Ethylene Plant Feedstock Contaminants Treatment" in Proceedings of the 7th Ethylene Producers Conference, Session 20, March 1995 combined AIChE and EPC meeting.

0 "Methanol Contamination of Polymer Caade Propylene Product at the Union Texas Petrochemicals Geismar Olefins Plant by L. Bayer; Presented at the 1996 AIChE Spring National Meeting, published in the Proceedings of the 8th Annual Ethylene Producers Conference.

0

0

"MTBE as a Feedstock Contaminant" by E. Stout; Presented at the 1996 AIChE Spring National Meeting, published in the Proceedings of the 8th Annual Ethylene Producers Conference.

Methanol in Cracking Furnaces; Presented at the 1996 AIChE Spring National Meeting, published in the Proceedings of the 8th Annual Ethylene Producers Conference.

Q Panel Discussion: Effect of Contaminants in Ethylene Plants; SESSION 22" Published in the Proceedings of the 8th Annual Ethylene Producers Conference.

0 D. J. Artrip, C. Herion and R. Meissner of BASF was presented on "Safeguarding Olefins Purity for Polyolef'm Plants", Proceedings of the 5th Ethylene Producers Conference, Session 15, March 1993 combined AIChE and EPC meeting.

10. D.L. Smith, "Olefin and Comonomer Purification Via Selective Adsorption to Assure Metallocene Catalyst Activity", Presentation at MetCon, Houston 1993.

11. Solubility of air (mole fraction) in kerosine or higher boiling petroleum oils (Henry's Law) by W. L. Nelson, Technical Editor and Petroleum Consultant in the "Oil and Gas Journal; July 11, 1966

12. "Chemical Refuting of Petroleum", American Chemical Society, Monograph Series; Reinhold Publishing Corporation, 1942

190

13. "Inhibiting Gum Formation in Modem Gasolines" by M.W. Schrepfer and C.A. Stansky of the UOP Process Division, UOP Inc.; Presented at the 1980 UOP Process Division Technology Conference

14. Quench Area Tutorial 3, Dilution Steam Feedwater Conditioning & Generation, PAPER NO. 97C by Greg Dunnells, ABB Lummus Global, Inc.; AIChE 2002 Spring National Meeting March 2002; New Orleans, Louisiana

15. Quench Water Pretreat in Ethylene Plant by Sabah Kuntkchi; PAPER NO. 97D, AIChE 2002 Spring National Meeting, March 2002; New Orleans, Louisiana, Ethylene Producers Conference 2002

16. Quench Water tutorial presented at the Ethylene Producers Conference in 2002.

17. Mono-olefins Chemistry and Technology by F. Asinger and Translated by B. J. Hazzatd; Published by Pergamon Press.

18. Petroleum Ref'ming, Vol 1; Crude Oil, Petroleum Products, Process Flowsheets; Institut Francais du Potrole Publications; Edited by Jean-Pierre Wauquier, Translated from the French by David H. Smith; Distributed in the United States by Gulf Publishing Company; 1995, Editions Teehnip- Paris, ISBN 2-7108-0685-1 and Series ISBN 2-7108-0686-X

20. "What are the amounts of nitrogen and oxygen in U.S. products?", by W. L. Nelson the Technical Editor and Petroleum Consultant in The Oil and Gas Journal of February 4, 1974.

21. Control of Carbonyl Polymer Fouling in Caustic Towers By David Mullenix Mike Jordan Hermie Bundick Fred Martin Vince Lewis

Vista Chemical Company Eastman Chemical Company Huntsman Corporation Betz Process Chemicals Nalco/Exxon Energy Chemicals

presented at the 8th Ethylene Producers' Conference and published by AIChE in 1996.

22. "An Overview of Olefin Unit Accidents and Safety Lessons Learned" by John A. Reid of Stone & Webster presented at American Institute of Chemical Engineers, 1999 Spring National Meeting and published in the Proceedings of the 1 lth Ethylene Producers Conference.

22. 2000 NPRA Q & A Session on Refining and Petrochemical Technology; pages 188-187.

23. Catalytic Reforming by Donald M. Little; PennWell Publishing Company of Tulsa, Oklahoma.

24. The Chemistry of Petrochemical Reactions By Lewis F. Hatch, Ph.D., Professor of Chemistry, The University of Texas; Gulf Publishing Company, Houston, Texas, 1955; The text of this book, was

191

presented originally as a seventeen-part series of articles during 1953 and 1954 in Petroleum Refiner magazine, published by Gulf Publishing Company.

25. Petroleum Refinery Engineering by W. L. Nelson; Consulting Petroleum and Chemical Engineer, Professor of Petroleum Refining, University of Tulsa; Fourth Edition, McGraw-Hill Book Company, 1958.

26. The Causes and Control of Fouling in Hydrodesulfurization Units, A Tutorial by Bruce E. Wright, P.E.; BetzDearbom, Inc., A Division of Hercules, Inc.; The Woodlands, TX; Copyright: December 2001, Prepared for presentation at the AICHE 2002 Spring National Meeting as Paper No. 57a.

27. Reduce Olefin Plant Fouling by J.F. Martin of Betz Process Chemicals, Inc., The Woodlands, TX; in Hydrocarbon Processing, November, 1988.

28. Pyrophoric Polymer in Ethylene Plant Deethanizer and Depropanizer Columns by Karl Georgieff of Gulf Canada Ltd.; in The Canadian Journal of Chemical Engineering, Vo132, June 1984.

29. Chemistry and Technology of Wines and Liquors By Karl M. Herstein, F.A.I.C.; Consulting Chemist and Thomas C. Gregory; Consulting Chemist; Published by D. Van Nostrand Company, Inc. in 1935.

30. INERT GAS + POOR PIPING = EXPLOSION; D. S. Alexander and C. M. Finigan, Polymer Corporation, Ltd; Petroleum Refiner, May 1959, pages 285-290

31. Petreeo Manual - Impurities In Petroleum - Occurrence, Analysis, Significance to Ref'mery and Petrochemical Operations; Prepared by the Staff of Petrolite Corporation Laboratories and Published by Petreco.

32. Significance of ASTM Tests for Petroleum Products; Prepared by ASTM Committee D-2 on Petroleum Products and Lubricants in 1955; Special Technical Publication No. 7-B; Published by the American Society for Testing Materials

33. Exxon Chemical's Guide on Storing/Handling Ol¢fins/Diolefins.

192

Figure 1

Acids (CnH2n+l COOH)

HCOOH formic acid

H--C~ O OH

Alcohols (CnH2n+l OH)

CH30H methanol

H J

H - C - O - H

H

CH3COOH acetic acid C H OH ethanol 25

H I //o

H-C--C I \ OH H

H H i t

H- C-C-O-H l l H H

C H COOH propionic acid 2 5

H H I I ~o

H-C--C-C\ I I OH H H

C3HTOH propanol

H H H I I I

H-C- C-C- O-H I I I H H H

C3H7COOH butyric acid C4H90H butanol

H H H J I I

H-C- C-C-C I l J H H H

//O \ OH

H H H H a i i i

H-C-C-C-C-O- H j I t l H H H H

193

Figure 2 . - .

R--COOH

Alipl,atic acids

H=C--CHC00H I I

H,C (CH:). \ /

CH,

Naphthenic acids

OH

---R

Pllenols (C,'esylic acids)

Figure 3

H=C--CHC00H I I

H=C CH= \/ CH=

Cyclopentanecarboxylic acid

H~C--CHCH=COOH I I

I-I,C CH, \/ CH=

Cyclopentylacetic acid

Figure 4

O H I

1 Phenol

CH,

ortho-Cresol

CH,

• ]~0H

recta-Cresol

CH,

't /

OH

para-Cresol

194

Vinyl Acetate 0 U

CH=- C-O-CH=CH2

Ethylene Glycol

H0- CH=- CH~ -OH

Isopropyl Alcohol CH~-CH- CH=

I OH

Figure 5 Morpholine

O / \ CH, CH, I I

CH= CH= \ N /

Sulfolane

CH= CH=

Ns ,/ 0 0

MEK 0 II

CH=-C-C=CH

Figure 6 Distribution of the acid content as a function of the specific gravity of successive distillation fractions.

T Moles of acid per mole of hydrocarbon

05 . . . . . .

0.4

0.3

0.2

0.1

J

/ /"

1 0.8 0.9 1

Specific gravity

195

Quench Oil System

(.o 03

From Cracking Furnaces

Recycle Furnace Effluent

Oil Reflux

H e a t

Recovew t p -

~ ,,,>I Steam --~

Coke Rejection

HFO

Heat Recovery

Quench Oi l

Tower

, T o

Water Quench

• ~ - - S t e a m

LFO

"=,

Fuel Oil

Product

Figure 7

D I S T I L L A T E & C O N D E N S A T E S T R I P P E R S

(.0

from quench section

m

(~ oil-water I -| separator [ / J

oil ~ - . . . . . . | reflux ~ ~ . 1

. . . . • ~ . .

1 ~ to debu tan ize r

acid gas removal

_ |

!

o Q. o.

, m

i n

u t

, to Recovery Section

to ,depropanizer

F i g u r e 8

Compression

(.o Qo

From

Quench

. J =

I

Cracked Gas Compressor

Figure 9

To

Recovery

. . . . . . .

. , l I I I I l I l I I

__._.~ ~__,N -1

,~,

QW Spent

Caustic Tower

Front n d Depropanizer/Hydro genation

Heat Pump C2H2 Hydrogenation

RX

(.o (.o

Cracked Gas Feed mm

from Dryers

To Cold Fractionation

_) To C3 Hydrogenation

I .

f C4+

Figure 40