Ethylene Production

AIChE Paper 220a Top 5 Contaminants in Ethylene Production Unit Feedstocks

Mark Brayden, Dow Chemical Dwight Hines, BASF Fina Petrochemicals James Graham, ExxonMobil Chemical Company Thomas Pickett, Shaw Stone & Webster Inc. Prepared for Presentation at the 2008 Spring National Meeting New Orleans, Louisiana, April 6-10, 2008

Contaminants • • • • • • • • • • •

Sulfur (42) Methanol (41) Sodium (36) Chloride (35) Carbon Dioxide (34) Mercury (34) Fluorides (28) Water (27) Metals (26) Arsine (24) Radon (23)

• • • • • • •

Ammonia (22) Phosphorus (18) Carbonyls (17) Iron (16) Organic Acids (16) NOx (13) Light Nitrogen Compounds (11) • Silicon (11) • Solvents (9) • Ethers (8)

Source: EPC 2004_55b "Feedstock Contaminants in Ethylene Plants -- An Update"

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Sulfur

Sulfur • Sources: Feedstock, Sulfiding agents • Partitions: All products • Reactions: Decomposition in furnace, acid-base, redox • Removal: Amine treaters, Caustic scrubbers, metal oxides. • Analytical: various ASTM methods, including Sselective detection, PbO tape. • Impact on Specifications: H2S in ethylene, COS in propylene, thiophene in benzene. 4

Methanol

Methanol • Sources: Feedstock, especially E/P (hydrate breaking), breakdown of ethers. • Partitions: Propylene, quench water, compressor knockouts. • Reactions: Decomposition in Furnace to CO. • Removal: Water Wash, Adsorbents (13X, alumina) • Analytical: GC with specialized detectors. • Impact on Specifications: Propylene 6

Coking

Sodium

Sodium • Sources: Brine / Seawater (Feedstock), caustic soda added to quench. • Partitions: Causes coking / corrosion of furnace tubes. • Reactions: Coke formation. • Removal: Feed coalescer, knockout, amine for pH control. • Analytical: AA, AE, ICP. • Impact on Specifications: Carbon Black Feedstock. 8

Carbon Dioxide

Carbon Dioxide • • • •

Sources: Untreated LPG feedstocks. Partitions: Cracked gas, ethylene. Reactions: Acid-base. Removal: Amine treater, caustic tower, adsorbent (13X). • Analytical: GC w/ specialized detector, IR. • Impact on Specifications: Ethylene. 10

References • Twenty-one listed in paper for further, more indepth coverage of these topics. – – – –

Sulfur (4) Methanol (5) Sodium (7) Carbon Dioxide (5)

• Primary sources are from past EPC papers. • Intend to be incorporated into contaminants spreadsheet to be discussed in paper 220x. 11

Future Plans • Covered in 2008 – – – –

Sulfur (42) Methanol (41) Sodium (36) Carbon Dioxide (34)

• Next Year? – – – – – – –

Chloride (35) Mercury (34) Fluorides (28) Water (27) Metals (26) Arsine (24) Radon (23)

– – – – – – –

Ammonia (22) Phosphorus (18) Carbonyls (17) Iron (16) Organic Acids (16) NOx (13) Light Nitrogen Compounds (11) – Silicon (11) – Solvents (9) – Ethers (8)

Source: EPC 2004_55b "Feedstock Contaminants in Ethylene Plants -- An Update"

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Disclaimer •

Neither the authors nor their respective employers represent, warrant, or otherwise guarantee, expressly or impliedly, the merchantability, fitness for a particular purpose, suitability, accuracy, reliability, or completeness of the information contained in this document or the products, materials, or processes described. The user is solely responsible for all determinations regarding any use of material or product and any process in its territories of interest. The authors and their respective employers expressly disclaim liability for any loss, damage, or injury directly or indirectly suffered or incurred as a result of or related to anyone using or relying on any of the information in this document. The authors and their respective employers do not endorse any product or process, and expressly disclaim any contrary implication.

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Top 5 Contaminants in in Ethylene Production Unit Feedstocks Mark Brayden

Process Research Leader Dow Chemical Dwight Hines Product and Process Technical Manager BASF Fina Petrochemicals James Graham Staff Chemist ExxonMobil Chemical Company Thomas Pickett Olefins Technology Manager Shaw Stone & Webster Inc.

Abstract: Trace contaminants in feedstocks to ethylene production units cause various processing issues and impact final product purity. This paper explores the top 5 feedstock contaminants that were identified in the 2004 survey paper, "Feedstock Contaminants in Ethylene Plants -- An Update". According to the survey, the top five contaminants, based on number of respondents reporting issues with it, are sulfur, methanol, sodium, chlorides, and carbon dioxide. Each impurity will be discussed in some detail as to the source of the contaminant, how it partitions in the plant, any reactions that it may undergo, how it is removed, analytical methods, and its impact on final product specifications.

Sulfur (Prepared by Thomas Pickett)

Sources

Sulfur generally enters olefins plants with the plant feedstock. It is also typically injected in relatively small quantities upstream of the cracking furnaces to minimize coke formation, manage CO & CO2 formation, and preserve furnace tube metal integrity. Volumes can be written on the topic of sulfur due to the variety of sulfur species, distribution of the various species within the plant’s recovery systems and the variety of removal techniques. This portion of the paper will touch on sulfur species most commonly encountered by olefins producers. Liquid Feeds Liquid feedstocks will typically contain the higher sulfur concentrations. There is generally a direct relationship between boiling point and sulfur content, assuming feeds have not been hydrotreated. Following are typical or expected levels which might be encountered for various feeds: Light Naphtha Heavy Naphtha Middle-East Condensate AGO

Total Sulfur 100-400 ppmw 200-800 ppmw 500-2500 ppmw 1000 ppmw-1 wt%

Gas Feeds (E/P/B): Most LPG recovery plants providing feed to ethylene plants will remove sulfur and CO2 to meet pipeline transportation requirements. Many gas fed ethylene plants have sufficiently low sulfur such that sulfur injection is required as indicated above. Ethane fed plants with high CO2 levels (>1000 ppm) will often install amine treaters in the feed to reduce caustic consumption costs. Amine treating will likewise remove H2S to very low levels. Refinery Sourced Streams (FCC Gas/Propane/Propylene): Light-end streams originating from refineries are especially troublesome with respect to contaminants and will normally require special treatment for H2S, mercaptan, and COS, as well as other non-sulfur bearing contaminants. Sulfur Injection: Furnace coils are fabricated with high nickel content. Nickel catalytically promotes coking reactions with CO and CO2 forming in the coils as a by-product of the cracking process. These side reactions can be “managed” in part via sulfur addition where sulfur is in-effect a poison to the catalyst sites. Common sulfiding agents are DMS and DMDS. Mercaptan can also be used if practically available. The sulfiding additive of choice is one which completely vaporizes prior to entering the furnace coils (normally injected into the dilution steam) and one

which dissociates principally to H2S. Most operators strive to achieve from 20-200 ppmw total sulfur in the furnace feed. The table below summarizes various ways sulfur enters the ethylene plants: Source Feedstock Furnace Injection

Sulfur Type H2S, mercaptans, COS, disulfides H2S, mercaptan, DMS or DMDS, elemental sulfur Vent Gas Recycle Stream H2S, COS, mercaptans, CS2 from gasoline hydrogenation units FCC and Coker Off-gas H2S, COS, CS2, mercaptans, SOx, thiophenes Vent and recycle streams H2S, mercaptans, solvents from downstream units Sulfur Compounds produced H2S, thiophenes, mercaptans, disulfides in cracking furnaces Sulfur added to front-end H2S, mercaptans raw gas type reactors

Sulfur Partition

Many sulfur compounds will dissociate or partially convert to H2S in cracking furnaces.

H2S:

Hydrogen sulfide will follow the ethylene plant light-ends, and if breakthrough occurs in the caustic tower, contamination will be seen in the ethylene and propylene product. COS

COS will mostly convert to H2S (~90%) in the cracking furnace. It is normally more of an issue for olefin plant operators receiving C3 or refinery off-gas streams which by-pass the furnaces. If left untreated, COS will primarily follow propylene through the plant recovery systems. A small portion will track with the C2’s, especially C2’s with high propylene content. Mercaptans Mercaptans must be examined in terms of methyl-, ethyl- and propyl-mercaptans. • • •

Methylmercaptan (CH4S) - Unconverted methylmercaptan exiting the cracking furnace, if untreated, will partition partially with the C3’s and partially with C4’s in the plant recovery system. Ethylmercaptan (C2H6S) - Unconverted ethylmercaptan exiting the cracking furnace, if untreated, will partition with the C4’s with a small portion into the C5’s. Propylmercaptan (C3H6S) - Unconverted propylmercaptan exiting the cracking furnace, will typically leave the plant’s quench system with the heavy pyrolysis gasoline.

Reactions

Amine based systems: H2S 2RNH2 + (RNH3)2S + H2S Caustic based systems: H2S + 2NaOH CH3S-H + NaOH C2H5S-H + NaOH Metal Oxide Reactions: H2S + PbO H2S + CuO COS + PbO COS + CuO

→ →

(RNH3)2S 2RNH3HS

→ → →

Na2S + 2H2O NaS-CH3 + H2O NaS-C2H5 + H2O

→ → → →

PbS CuS PbS CuS

+ + + +

H2O H2O CO2 CO2

Removal

The following table summarizes conventional removal methods for various sulfur species: Species H2S (Gas Cracker) H2S (Gas Cracker) H2S (Liquids Cracker) H2S (general) COS Mercaptans

Removal Technique Amine Treatment in Plant Feed system when CO2 >1000 ppmw, followed by caustic treatment in the cracked gas compression (CGC) system. Caustic Treatment in the CGC system when (CO2 250 ppmv) can be removed via single and/or double water wash systems. If the washed feed is to be introduced directly into a steam cracking furnace, it should be noted that the water quality should be clean cold steam condensate or cold boiler feed water with low total dissolved solids to avoid negatively impacting furnace operability. Molecular sieves can remove trace amounts (< 50 ppmw) of MeOH in C3 streams. While 3A molecular sieve is too small to absorb MeOH, the larger pore molecular sieves such as 4A, 5A, or 13X will absorb MeOH when operated to avoid water breakthrough since water will displace any absorbed MeOH. Since some molecular sieves can produce propylene dimers

and higher order polymers (green oil) during regeneration and each can have varying capacities and regeneration requirements, it is recommend vendor input be obtained when designing and/or using molecular sieves in a MeOH removal application. Activated alumina systems can remove trace amounts of MeOH. Alumina systems, that require regeneration gas temperatures of 500 – 550°F, have the highest MeOH removal capacity of any system in terms of lbs per 1000 lbs of active bed material. Vendors offer products for both MeOH and water removal that require different regeneration conditions and offer varying MeOH removal capacities. As with molecular sieves, it is recommended vendor input be obtained when designing and/or using activated alumina in a MeOH removal application.

MeOH Removal Option Locations

MeOH process removal facilities can be located on the C3 splitter feed or the propylene product stream. Advantages and disadvantages of these locations are summarized in Table 1 below: Table 1. Location of MeOH Removal Facilities in Olefin Plants (advantages and disadvantages) Location C3 propylene product C3 splitter feed stream stream Advantages Reduced flow rates MeOH has no opportunity to concentrate in C3 splitter resulting in potential for a MeOH slug into propylene product that may overload downstream treatment facilities Reduce MeOH load If CO or Green Oil is produced during regeneration and enters the C3 splitter, they will not concentrate in the propylene product Disadvantages Potentially introduce CO CO absorbed on the adsorbent from from regen gases into the tail gas during a regeneration can propylene product desorb into the C3 feed steam when on-line and enter the C3 splitter. The majority of the CO in the C3 splitter exits with H2 and CH4 from the reflux drum, but a small fraction of CO can end up in the propylene product. This may become an issue with lower propylene product CO specs. Potentially introduce green oil from regen gases into propylene product

MeOH Analytical

MeOH can be measured in hydrocarbons by standard GC techniques using various quantitative detectors and polar separation columns. Various techniques may also require the sample be extracted prior to analytical detection. ASTM and UOP have published standardized test methods for the quantitative detection of MeOH in various hydrocarbon matrices as listed below: •

• • •

ASTM D4815 - Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, tertiary-Amyl Alcohol and C1 to C4 Alcohols in Gasoline by Gas Chromatography ASTM D4864 - Standard Test Method for Determination of Traces of MeOH in Propylene Concentrates by Gas Chromatography ASTM D7059 - Standard Test Method for Determination of MeOH in Crude Oils by Multidimensional Gas Chromatography UOP 569-79 – Methanol in Petroleum Distillates and LPG by Gas Chromatography

MeOH Impact of Final Product Specifications

Off-spec MeOH in Propylene product is a major concern for downstream polymer plants as MeOH and other oxygenates are significant poisons for the transition metal catalysts utilized to generate polypropylene.

References 5. Nowowiejski, G. and Reid, J., “An Overview of Oxygenates in Olefins Units in Relation to Corrosion, Fouling, Product Specifications, and Safety”, EPC Paper 56a, 2003. 6. Reid, J. and McPhaul, D., “Contaminant Rejection Technology Update”, EPC Paper 21c, 1996. 7. Graham, M., “Selected Ethylene Feedstock Impurities: Survey Data”, EPC Paper 15d, 1993. 8. EPC Discussion Panel, “Section 22 Questions and Answers”, EPC Document 22disc, 1996. 9. Stout, E., “MTBE as a Feedstock Contaminant”, EPC Paper 22b, 1996.

Sodium (Prepared by Dwight Hines)

Sources

The sodium compounds most often associated with contamination in steam crackers are sodium chloride (NaCl) and sodium hydroxide (NaOH). However, drying agents such as sodium sulfate (Na2SO4) could also be involved. Sodium chloride sources usually include brine from feed caverns and ballast from barges and ships containing liquid feeds. Sodium contamination is seen most often in liquid feeds containing water. However, entrained drier material could also be found in liquid feeds, LPG’s or even gas feedstocks. Sodium hydroxide is often used for pH control in quench water used to make dilution steam. NaOH can then easily be entrained in dilution steam that is fed back to the furnaces.

Reactions

A variety of reactions are reported for sodium compounds in furnaces. Arguably, the most common is the reaction of sodium with furnace tubes is the formation of volatile sodium chromate. Parks and Schillmoller (10) report “Sodium is an especially bad actor as it breaks down the protective oxide film by formation of volatile sodium chromates. Its concentration should be controlled to below 500 ppb.” As the oxide film is removed surfaces are left unprotected and iron/nickel catalytic surfaces are exposed. Catalytic coke is formed until the exposed surface is covered and asymptotic coke begins to form from the gas phase hydrocarbon. The asymptotic coke is a softer “tar-like, amorphous coke that dehydrates with time and dries to a grayish brown color of very fine grain and high in chromium”. In 1996 Ray Orriss (11) presented a paper at the EPC entitled “Effects of Contaminants in Ethylene Plants: Sodium and Iron”. In this paper, he outlines a basic mechanism of sodium attack. The mechanism begins with the sodium compound from the feed forming sodium sulfate (Na2SO4) with the furnace sulfur in an oxidizing steam environment. It is then reduced to sodium sulfide (NaS) at the metal sites on furnace radiant tubes. The sodium then reacts with the chrome carbides to form chrome sulfide and carbon which results in a tube that is “primed” for increase rates of catalytic coking. He reports that Kellogg has demonstrated such coking in laboratory tests resulting in coking 50 to 100 times higher than normal levels. In a prior presentation in 1994 (12), Ray Orriss further states that the initial reaction forming Na2SO4, removes some of the sulfiding agent (added to coat tubes and prevent coking) and therefore reduces the effectiveness of the sulfiding agent. In the 1994 presentation (12), he further explains this “priming” mechanism. He states iron and nickel (both available in bare radiant tubes) promote filamentous catalytic coke. He cites a reference from Baker (13) et al that shows the rate of coking is directly proportional to the available bare surface area of the tube and that Bernardo and Trimm (14) reported enhanced coking on a nickel foil. Therefore, this is the reason for much of the work done on protecting active sites with inert layers and presulfiding of furnace tubes. Another mechanism reported for sodium attack on furnace tubes is molten salt corrosion, (also called hot salt corrosion). Attack by sodium chloride on austenitic steels including alloys such as 800 H used in the convection section shield coils with subsequent slag formation and slag migration was first mentioned in the 1994 presentation (12). Molten salts

such as Na2SO4, NaCl and CaSO4, generally are good fluxing agents, effectively removing oxide scale from a metal surface. The corrosion reaction proceeds primarily by oxidation, which is then followed by dissolution of metal oxides in the melt. Oxygen and water vapor thus accelerates the hot corrosion by re-oxidation of the surface metal, (especially during steam-air decoking) and by oxidation of sulfur, (by steam) in a feedstock to create small amounts of SO4. As water evaporates when the liquid feedstock is heated to the dry point in the convection section, salt crystals form, and stick to the tube surface. In time they build up and form an insulating layer, resulting in increased metal temperatures. Once the tube material attains the melting temperature of these salts, they cause hot corrosion. Commonly a lower melting point eutectic is formed by a mixture of salts. The slag-like appearance of such corrosion deposits results from a mixture molten salts with metal oxides dissolved in it slowly moving or flowing in the affected tube. In addition, the melt is often sticky enough at operating temperatures to capture coke and rust particles that impinge upon it, causing further growth of the slag. Such slag deposits tend to accumulate in the U bends of the shield coils causing the U bends to fail, but can migrate further downstream and cause flow maldistribution problems as stated in the 1994 presentation (12).

How Sodium Compounds Partition

While most sodium can be captured on tube surfaces inside ethylene furnaces, removal of sodium from a feedstock by its capture in the furnaces is not always complete. Sodium compounds can exit the furnace quench exchangers and will usually partition with the heavy streams from the gas fractionators such as tar or fuel oil. Should sodium be entrained with other lighter streams, they would tend to partition with the quench water due to high water solubility of most sodium compounds. These are removed in blowdowns from the water system. Sodium in the heavy streams posses a problem if these streams are used as carbon black oil feedstocks. These have relatively low sodium specifications.

Removal

The first line of defense is water removal by draining feed tanks and equipment where water accumulates, that of course requires sufficient settling time to allow adequate water separation to occur. Heavier, higher viscosity feedstocks will require more settling time or may require additional steps for water removal. Feedstock maximum haze and other maximum water content specifications should be rigorously enforced since water in feed systems is rarely benign and commonly contains salt. Last year Mark Brayden from Dow Chemical presented a paper (15) summarizing the merits of filtration and coalescence. In his paper he shows the benefits of high efficiency coalescers to remove water and water soluble salts, while filtration removes particulates such as iron and debris. He shows that sodium compounds are effectively removed using this technology. Many ethylene plants that take liquid streams from refineries use desalting technology (11) to remove sodium salts from salt driers or ship ballasts.

A recent patent (16) outlines a vessel that can be used upstream of the furnaces to remove salts and particulates in very heavy feeds such as crude oil and heavy resids. This one stage flash vessel operates at a temperature to allow lighter molecules into the cracking furnace and heavy molecules with the solids and salts to exit in the bottoms stream back to the refinery.

Analytical

Several analytical techniques are used to measure sodium. These include Atomic Absorption (AA), Atomic Emission (AE) and Inductively Coupled Plasma Emission Spectroscopy (ICPES). Each of these techniques can measure low levels of sodium even into the ppb levels. Classic techniques use “dry ashing” (or sulfated dry ashing) to prepare the sample for analysis. In these methods a suitable sample size is used to get the required detection limit. The samples are weighed into a crucible and placed in a muffle furnace for a specified time in air to vaporize the organic part of the sample. The resulting salt is dissolved in a dilute acid to be measure by the above techniques. Less used for sodium are wet ashing techniques. In the past few years the detection limits for analytical techniques have improved. This allows the analyst to measure the hydrocarbon directly and maintain a low detection limit. To do this the ICPES can be equipped with a Direct Injection Nebulizer (DIN) to atomize the sample into the plasma. Many labs simply water wash the sample to extract the sodium salts and use the above techniques. This technique would not extract organo-sodium compounds, should they be present, though no references for such compounds were found by this researcher.

Impact on Final Product Specification

As mentioned above, the primary specification impacted is any heavy streams such as steam cracked tar that are used for carbon black feeds.

References 10. Parks, S. B. and Schillmoller, C.M., “Update in Alloy Selection for Ethylene Furnaces”, EPC Paper 24a, 1995. 11. Orriss, R., “Effects of Contaminants in Ethylene Plants: Sodium and Iron”, EPC Paper 22ba, 1996. 12. Orriss, R., “Ethylene Plant Contaminants”, Opening address at 1994 EPC Conference, Atlanta, Georgia. 13. Baker, R.T.; Harris, D.S.; Thomas, R.B. ; and Waite, R.J.; Catalysis, 30, 86 (1973) 14. Bernardo, C.; and Trim, D.L.; Carbon, 14, 225 (1976). 15. Brayden, M.; Wines, T.H.; and Del Giudice, K., “Improve Steam Cracking Furnace Productivity and Emissions Control Through Filtration and Coalescence”, EPC Paper 218a, 2006. 16. McCoy, J.N,; DiNicolantonio, A. R.; Frye, J. M.; Stapleton, M. D.; and Stell, R. C., Patent WO/2005/113714, 2005.

Chloride

Carbon Dioxide (Prepared by Mark Brayden)

Sources

The primary sources of carbon dioxide (CO2) in the feed-streams to an ethylene production plant are vapor feedstocks derived from natural gas liquids (NGL), primarily, ethane and propane. In the 2004 Feedstock Impurities Survey (17), the presence of CO2 in ethane was listed by 66 % of respondents as either a high or medium concern in ethane. Likewise, 37 % listed it as a high or medium concern for propane or other NGL’s, but no one listed it as a problem in heavier feedstocks like raffinate or naphtha. Finally, 67 % of respondents listed CO2 as a medium concern for refinery dry gas. From this same survey CO2 was reported at various levels in these feed types: ƒ 0-40,000 ppm range with 100 - 500 ppm (average) in 23 ethane or E/P mixes ƒ 0-500 ppm range with < 100 ppm average in ten propane rich samples ƒ 100-500 ppm range with 300 ppm average in two samples of refinery dry gas Carbon dioxide is also formed in the pyrolysis or cracking furnace. Often, a sulfur compound like dimethylsulfide (DMS), dimethyldisulfite (DMDS), or tert-butylpolysulfide (TBPS) is used as an additive to passivate catalytic metal surfaces to suppress carbon monoxide (CO) and CO2 formation. Even so, there will be a period of elevated CO and CO2 formation during the initial startup of a freshly decoked furnace. Furthermore, even after the furnace is passivated by the sulfur additive or by a coke layer, CO2 is produced by reforming reactions. Secondary sources include natural gas containing high CO2 used for commissioning, especially when starting up supported catalysts or adsorbents downstream of the acid gas removal system. Carbon dioxide adsorbed during commissioning can be later released into the cracked gas and end up primarily in the ethylene product. CO2 in product can also come from COS removal beds, which convert COS to CO2 and water. If a metal oxide bed is used for this purpose, generally a CO2 removal bed will also be required. (18) In 1999 Reid (19) reported on natural gas infiltration into salt dome caverns used for storage. Reid reported two instances of ethylene contamination on the US Gulf Coast. Since product ethylene specification for CO2 is generally a few ppm, only minor contamination by natural gas infiltration can cause out of specification ethylene product. One might assume, then, that if these same caverns are used for storage of cracker feedstocks, the natural gas infiltration would probably not exceed levels that would be problematic for the plant.

How CO2 Partitions

CO2 typically follows the ethylene product, but can also be an impurity in other streams in an ethylene plant as described in last year’s paper presented by Hood and Coleman, specifically, as a bicarbonate salt in the C4 and C5 streams. This salt can then decompose back to CO2. (20)

Absorption of CO2 in quench water removes a fraction of the CO2 from the product gas, forming carbonic acid in the water. Carbon dioxide is the most plentiful acid gas in the product gas stream, as well as being a stronger acid than hydrogen sulfide, the other abundant acid gas in pyrolysis gas. There are other acids that may be present in the gas, some even stronger acids like acetic acid, but primarily the dissolution of CO2 into the quench water is the primary cause of low pH of the quench water. This can lead to corrosion problems in the quench and dilution steam systems. CO2 can also surface adsorb on molecular sieve 3A, only to be displaced later by other adsorbed species, most commonly water vapor. This can be affected by going to a larger pore molecular sieve to allow the CO2 to penetrate the pores of the sieve, or to a selective adsorbent that allows the CO2 to absorb / adsorb in the internal pore structure of the adsorbent.

Reactions

Since CO2 is an acid gas, it can be absorbed into water and then reacted with a base to form a bicarbonate or carbonate salt. In this manner, this marginally soluble gas compound can be held in water as the bicarbonate or carbonate at percentage levels. This is the basis for amine and caustic scrubbers. The acid-base reaction is rapid, and the rate-limiting step in an absorber is the transfer of the CO2 from the gas to the liquid phase. In the pyrolysis furnace, CO2 is formed by the reaction of formed CO with steam added for coke suppression by the water-gas shift reaction and by reforming reactions. (21) Carbon dioxide can surface adsorb onto molecular sieve 3A. It can be effectively adsorbed by various treated aluminas or molecular sieve 13X. Carbon dioxide will combine with hydrogen sulfide to form carbonyl sulfide in the presence of 4A or larger pore molecular sieves. This reaction does not occur across 3A.

Removal

The primary method of removing CO2 from the feed is by an amine treater, using MEA, DEA, MDEA, or any of various other formulated amines for this purpose. The amine treater is typically located at the NGL fractionation plant. An amine treater can also be located at the entrance to the ethylene plant prior to the pyrolysis furnaces, especially when the vapor feedstock is untreated and contains high levels CO2. The amine can be regenerated and reused, releasing the CO2 into a fuel gas stream or sent to a flare. To remove CO2 in the pyrolysis gas, typically a caustic scrubber is employed. In some plants, amine scrubbers are also used to remove the bulk of the acid gases. Since an amine scrubber will not remove CO2 to sub-ppm levels, it is followed by a caustic tower as a secondary absorber to get to sub-ppm levels. The spent caustic containing carbonate is generally sent to a waste treatment system like a wet air oxidation unit before being sent on for biological waste treatment. Like the amine scrubbers used for feed treatment, amine scrubbers in cracked gas service are also regenerable. In product ethylene trace levels of CO2 are removed with a selective adsorbent like 13X or a treated alumina, usually at the block entrance to a user’s plant like a polyethylene production unit.

Analytical

Since CO2 is at a low level in product and the response of CO2 is very poor on a flame ionization dectector (FID) and non-responsive on other common lab GC detector, the laboratory analysis that has been most commonly used is a gas chromatograph equipped with a thermal conductivity detector or flame ionization detector (FID) in combination with a methanizer, which utilizes a nickel catalyst to convert any CO2 in the stream to methane. For several years now a commonly used method of detecting CO2 is a field infrared analyzer. Sensitivity is gained by employing a long path length IR cell to see down to the subppm levels. For some troubleshooting activities, sub-ppm analysis of CO2 is needed. One approach was presented in 2007 using a GC equipped with a pulsed discharge detector. (22)

Impact on Final Product Specifications

The primary problem with CO2 in the product is as a catalyst poison for polyethylene production. With new higher efficiency catalysts, the presence of even sub-ppm levels of impurities can cause catalyst efficiency losses. Typically, an adsorption unit is in place to protect these sensitive processes.

References 17. Baumgartner, A. J.; Blaschke, M. W.; Coleman, S. T.; Kohler, R.; and Paxson, T. E., “Feedstock Contaminants in Ethylene Plants – An Update”, EPC Paper 55b, 2004. 18. Polito, C., “Arsine and Carbonyl Sulfide Contaminants in Ethylene Plant Feedstocks”, EPC Paper 22h, 1996. 19. Reid, J., “Natural Gas Infiltration into Salt Caverns - Attachment 4”, EPC Paper 69e, 1999. 20. Hood, D. and Coleman, S., “Minor Components, Major Issues: An Overview of Contaminants in Ethylene Plants”, EPC Paper 51c, 2007. 21. Nowowiejski, G. and Reid, J., “An Overview of Oxygenates in Olefins Units in Relation to Corrosion, Fouling, Product Specifications, and Safety”, EPC Paper 56a, 2003. 22. Sun, K., et al, “Analysis of ppb Levels of H2, O2, N2, CH4, CO and CO2 in Hydrocarbon Feed Streams with a PDD Detector”, EPC Paper 51a, 2007. Neither the authors nor their respective employers represent, warrant, or otherwise guarantee, expressly or impliedly, the merchantability, fitness for a particular purpose, suitability, accuracy, reliability, or completeness of the information contained in this document or the products, materials, or processes described. The user is solely responsible for all determinations regarding any use of material or product and any process in its territories of interest. The authors and their respective employers expressly disclaim liability for any loss, damage, or injury directly or indirectly suffered or incurred as a result of or related to anyone using or relying on any of the information in this document. The authors and their respective employers do not endorse any product or process, and expressly disclaim any contrary implication.