Improve Steam Cracking Furnace Productivity and Emissions Control Through Filtration and Coalescence

Scientific & Technical Report GDS138

Improve Steam Cracking Furnace Productivity and Emissions Control through Filtration and Coalescence

Mark Brayden, Process Research Leader, The Dow Chemical Company Thomas H. Wines, Ph.D., Senior Marketing Manager, Pall Corporation Ken Del Giudice, Senior Project Manager, Pall Corporation

The impact of feedstocks on the operation of an ethylene plant April 26, 2006

Presented at the American Institute of Chemical Engineers (AIChE) Spring National Meeting, Ethylene Producers’ Conference (EPC)

Orlando, Florida, April 23 – 27, 2006

Abstract

Hydrocarbon streams feeding ethylene steam culty in maintaining the optimum furnace tem- cracking furnaces often contain significant lev- perature and steam/hydrocarbon feed ratio. This els of corrosion products, water, and salts. This can lead to poor yield of ethylene by the crack- is especially true when naphtha is supplied by er and undesirable by-products. marine vessels. In these cases, high efficiency Installation experience at The Dow Chemical liquid–liquid coalescers and filters are recom- Company (Dow) in Freeport,Texas is presented mended to condition the inlet feed stream. for the use of high efficiency liquid–liquid coa- Contaminants in the inlet hydrocarbons can lescers and filters to extend the steam cracker adversely affect ethylene production in a num- service life between decokings. The naphtha ber of ways. Sodium and iron oxides are known feed was supplied by marine transport and con- to be coke promoters, and their presence can tained significant salt water contamination. An reduce the run time of the ethylene furnaces economic evaluation of the savings due to before decoking is required, and in some improved operation efficiency and the payback instances reduce the life of the furnace tubes by period for the coalescer system is provided. as much as one third. Unscheduled or frequent The installation of the high efficiency decoking cycles lead to a loss in ethylene pro- coalescer–filtration system was found to have a duction, shortened furnace tube life, and create payback of less than ten months based on extend- higher maintenance costs. Frequent decoking ed furnace run times alone, assuming that will also result in increased particulate release to ethylene production is limited by furnace avail- the atmosphere and can create environmental ability. concerns over excessive emissions. Fouling of flow meters and control valves can lead to diffi-

Introduction

Rising costs for raw materials and ever-increas- The cracking of LCN or FCC gasoline is a recent ing competition have made margins in ethylene trend, due to the new 2005 specifications on production slim in recent years. Many produc- refining products.While all feed stocks can bring ers are looking for ways to reduce costs, includ- solids due to pipe corrosion, LCN or FCC gaso- ing using alternate feed stock supplies such as line has additional sodium contamination due to those shipped in by marine vessels,or the use of previous treatment to remove sulfur compounds. Light Catalytic Cracked Naphtha (LCN) or The desulfurization process includes a caustic Fluidized Catalytic Cracked (FCC) gasoline. wash step that results in high sodium concen- While alternate steam cracker feed stock sources trations that should be removed prior to the fur- can reduce raw material costs, they also pose naces. new challenges to ethylene producers. Contamination in the feed stocks can include corrosion products,water,and salts. Marine transport vessels may also use the same tanks for sea- water ballast as they use for hydrocarbon feed stocks, thus creating a greater risk of contamination to steam cracker furnaces.

1 Contaminants in the inlet hydrocarbons can • During decoking cycles,significant amounts of adversely affect ethylene production in a num- particles are released to the atmosphere: ber of ways: The total annual emissions can be reduced as • Sodium and iron oxides are known to be coke the number of cycles is decreased. promoters [1,2] and their presence can reduce Separation of the harmful contaminants can be the run time of the ethylene furnaces before a difficult task especially when the salt water is decoking is required. Unscheduled or frequent emulsified with the hydrocarbon feed stock. decoking cycles can lead to a loss in ethylene Fortunately, new liquid–liquid coalescer tech- production, shortened furnace tube life, and nology has been developed to separate even the higher maintenance costs. most difficult emulsions. • Fouling of flow meters and control valves can Experience with high efficiency liquid–liquid lead to difficulty in maintaining the optimum coalescers and filters at The Dow Chemical furnace temperature and steam/hydrocarbon Company (Dow) in Freeport,Texas is presented. feed ratio. This can result in a poor yield of The naphtha feed is marine transported,and both ethylene by the cracker and undesirable sodium and iron needed to be removed prior to byproducts. the cracking furnaces. Details of the filtering • Coke fines and sodium are often released inad- and coalescing systems are provided along with vertently into the downstream quench sys- the separation performance, process benefits, tems during decoking cycles and this can lead and payback period. to further complications in the decanter and downstream separation units, including the quench water stripping tower and heat exchangers in the dilution steam system.

Solid and Salt Water Contamination in Naphtha Streams

Solid contamination Analysis of solid contamination in naphtha Solid contamination in naphtha performed on steam crackers A recent study based on 36 samples of naphtha Analysis of different naphtha feeds was performed cuts from 19 refineries worldwide (11 different on crackers prior to the furnaces and are con- oil companies) showed that the quantity of solids sistent with the study on refineries: in naphtha varied between 1 and 10 ppmw. The Table 1: Naphtha solid contamination: particles were composed of iron oxides and iron measurements of TSS* on naphtha sulfides with a size range between 2 and 70 crackers micron (µm) and an average size of 10 µm [3]. Location TSS value Depending on the naphtha cuts (catalytic cracked USA plant 1 1.2 to 1.5 mg/l naphtha, naphtha straight run as examples), the USA plant 2 4 to 6 mg/l particle content may be significantly different. Filters have already been successfully installed for Japan 1.3 mg/l the protection of naphtha hydrotreaters in refiner- Average 3 mg/l ies. * Total Suspended Solids

2 A photomicrograph of typical solid contaminants 20 dyne/cm indicates that the emulsion is very in naphtha is presented in Figure 1. The stable. Under such conditions,separation in stor- red–orange colors are indicative of iron oxides age tanks is ineffective except for bulk water while the black particles are representative of removal, and a small percentage of emulsified coke fines and iron sulfides. water would be expected to remain in a stable form, requiring the use of high efficiency Figure 1: Photomicrograph liquid-liquid coalescers for separation. of naphtha solid contaminants at Depending on variations in process operations, 100 X magnification interfacial tensions can vary dramatically.At the refinery where naphtha is produced, corrosion inhibitors (filming amine type) are typically inject- ed into the overhead column to minimize corrosion in the separation drum and overhead heat 100 µm exchangers.Variations in inhibitor content can significantly affect emulsion stability of water in Based on the analysis of thirty six different naph- naphtha. tha streams,it can be stated that the typical solid High Solids Loading Naphtha Filter: Naphtha contamination in naphtha is in the range of 1 to feed stocks can contain significant solid partic- 10 ppmw in crackers and refineries.Iron oxides ulate in the form of corrosion products (iron and iron sulfides represent the main part of the oxides,iron sulfides),and in lower quantities silt solid contamination with more than 80% of the (sand,clay) or precipitated salts (sodium chloride, particles having sizes below 70 µm, and an aver- sodium sulfate,etc.).In some cases,aqueous con- age size of 10 µm. taminants are not present, and in others, both The naphtha filter rating: finding the best aqueous and solid contaminants need to be compromise to optimize furnace protection removed. Therefore, in some instances, the feed Typically, large solid particles (>300 µm) are stock may require stand-alone particulate filtra- removed in the storage tanks or by coarse mesh tion,and in others cases,incorporate a coalescer filters installed upstream of the furnaces.However, system with pre-filters. for efficient protection of furnace tubes, the In order to protect the steam cracker, a filter removal ratings of the naphtha filters should be with an absolute rating of 10 µm should be used. lower than 70 µm absolute.Considering absolute Several types of filters are available, including filter efficiencies, and the particle size distribu- string wound,pleated,depth,and advanced high tion in the naphtha, a 10 µm absolute rating is flow capacity designs that use laid over, cres- recommended. Since 1998, the plants having cent-shaped pleats. When the solids loading is such filter installations have reached the expec- high, backwash type filters become more eco- tations in terms of furnace protection and cost nomical than disposable type. Here, the initial operation. capital investment is higher, but the operating Emulsified water costs are much lower since the filters are regen- Laboratory tests determined that the interfacial erable and can last years before requiring clean- tension between water and naphtha at the cracking. An example of a high flow capacity horizontal ing plants and in refineries ranged from 1 to disposable filter system is shown in Figure 2: 24 dyne/cm. An interfacial tension below

3 Figure 2: er droplets are easier to separate from the con- High flow capacity pre-filter offering tinuous hydrocarbon phase liquid.The enlarged high surface area. coalesced drops are then removed from the hydrocarbon phase by a separator cartridge that repels the water drops but allows the hydrocarbon to flow through. An illustration of the vertical high efficiency liquid-liquid coalescer system is given below in Figure 3:

High Efficiency Liquid-Liquid Coalescers: The separation of emulsified water in the feed hydrocarbon to the steam cracker can be a difficult proposition.Settling tanks,vane separators, Coalescer and mesh pads will not break emulsions and can Prefilter allow harmful contaminants to pass through. Separator Traditional liquid-liquid coalescers use glass fiber media and are adequate for easy to separate emulsions with interfacial tensions greater than Fuel or Aqueous 20 dyne/cm,but will not work for more difficult chemical with phase out Water free water and solids fuel or emulsions. At interfacial tensions below Fuel or chemical and chemical out 20 dyne/cm, surfactants adsorb onto glass fiber water without dirt media,rendering them ineffective at coalescing. Figure 3: High efficiency coalescer system with coalescer This phenomenon is known as “disarming.” elements stacked on top of separator elements. Pall Corporation has developed and patented new non-disarming coalescer media that is con- The high efficiency liquid-liquid coalescer oper- structed with novel, formulated polymers and ates in three stages: 1) separation of solids; fluoropolymers. These high efficiency coalescers 2) coalescence; and 3) separation of coalesced are effective for emulsions having interfacial ten- drops. sions as low as 0.5 dyne/cm [4] and have been Separation of Solids: Suspended solids can used for difficult separations, including water- increase the stability of an emulsion and reduce methanol from LPG [5] and caustic from gasoline the effective life of the coalescer. Effective pre- [6]. Naphtha feed stocks at an ethylene plant in filtration to remove these solids is an important the Benelux were found to have interfacial ten- consideration for a coalescer system. Types of fil- sions with water as low as 1 dyne/cm [7]. High ter systems are discussed in a previous section, efficiency, polymeric coalescers have produced “High Solids Loading Naphtha Filter.” clean petroleum fuels with free water concen- Coalescence: In this stage the pore dimensions are trations of <15 ppmv when challenged with inlet very fine at the beginning and become more open dispersed concentrations of up to 10%. The typ- to allow void space for coalescing droplets. The ical life of the coalescers is greater than one year inlet dispersion containing fine droplets between and the pre-filters generally last several months, 0.2 to 50 µm is transformed into a suspension of making the use of high efficiency liquid-liquid coa- enlarged drops ranging from 500 to 5,000 µm. lescers economical. The coalescence mechanism involves adsorption High efficiency liquid-liquid coalescers merge of droplets onto the coalescer fibers,followed by small droplets of the aqueous phase liquid into translation along the fibers and collisions at the larger ones as the fluid stream passes through sev- junctures between fibers. In these collisions,the eral layers of filter media,each with progressively droplets merge together,or coalesce.The viscous larger pores. As droplets compete for open pores, drag of the bulk fluid stream then causes the

4 they coalesce to form larger droplets. The larg- enlarged drops to disengage from the fibers.This drops, so only the water-free bulk hydrocarbon process is repeated a number of times through fluid passes through the separator. In Pall the coalescer depth until the large, coalesced Corporation’s design,the coalescer is stacked on drops exit the coalescer media [4]. top of the separator.This design ensures evenly Separation of Coalesced Drops: Once the droplets distributed flow to the separator and enhances have coalesced, separation is achieved by using performance. The aqueous phase collects in an a separator cartridge that deploys a hydrophobic internal sump. A level control system is used to medium. The separator repels the aqueous phase drain out the collected aqueous phase and main- tain the hydrocarbon level.

Plant Experience

Plant experience at The Dow Chemical by increased steam cracker run times. High effi- Company’s,Freeport,Texas site is described below. ciency liquid–liquid coalescers on similar naph- Included are operating data and plant benefits tha streams in ethylene plants have been found resulting from the use of high efficiency to reduce the sodium content down to liquid–liquid coalescers and filters on the feed < 0.2 ppm Sodium [7]. naphtha. In order to optimize the coalescer–filter system Process Parameters operation, a twofold approach was adopted. The process conditions for naphtha feed are Alternate coalescers and filters were selected given below in Table 2: that were capable of processing higher solids loading and a process change was also under- Table 2: Process conditions of naphtha feed to steam crackers taken. Coalescer– Filter optimization: The AquaSep Pressure 200 psig coalescers were replaced with PhaseSep® coa- Temperature 80°F lescers that are designed with a fluoropolymer Viscosity 0.41 cP construction and are able to process higher solids compared to the AquaSep coalescer design.The Inlet Water Concentration 1 – 2% pre-filter grade was changed from the original two Sodium Content in Water 13,000 ppmw micron absolute to a coarser ten micron absolute. Magnesium Content in Water 1,300 ppmw Process Optimization: Originally the naphtha Total Inlet Sodium Content 130 – 260 ppmw was fed directly to the coalescer–filter system by a pipeline connected to the unloading marine Filter and Coalescer Systems Operation transport. A holding tank was installed on shore Experience subsequently,and this allowed for settling of the The high efficiency coalescer unit was installed larger particulate and reduced the load to the in January 2004. This system consisted of 104 high coalescer–filter system. The feed source was efficiency AquaSep® polymeric liquid-liquid coa- changed from the pipeline to the shore tank in lescers with 104 stacked separator cartridges July 2004. (both 20 inch length by 4 inch diameter) to treat These changes optimized the system and allowed a maximum design naphtha flow. A separate fil- for economical prefilter service life of over two ter system consisting of 36 Ultipleat® high flow months while protecting the coalescers from glass fiber filters with an advanced laid over,cres- solids fouling. The PhaseSep coalescer system cent shaped design (60 inches length by 6 inch has experienced a coalescer element service life diameter and 2 micron absolute rating) was used of over a year and has consistently removed large to protect the coalescers. volumes of salt water reducing the harmful sodi- After start up,the naphtha was found to contain um content that was being fed to the steam crack- higher solids than originally expected and this led er. The operation of these systems has met or to prefilter service life of less than two weeks. exceeded the design requirements in terms of The coalescer, however, was effective in remov- service life and performance regarding furnace ing large volumes of water and lowering the sodi- protection. 5 um content in the outlet naphtha as evidenced Operation Data

The operating data for the coalescer–filter system 4 psid.The coalescer can operate effectively up at Dow is presented for the period of January to 15 psid and the typical service life for these 2004 to January 2005 for water drain operation, coalescers is 2 years. The data indicated in Figure coalescer differential pressure, pre-filter differ- 5 show that the coalescer is operating within ential pressure and the system naphtha feed flow design specification and has plenty of service rate. In Figure 4,the data collected for the water life remaining. drain operation is given. Water is collected in the

coalescer sump and accumulates. An automatic 8 drain is opened at different intervals triggered by 7 an upper limit sensor. Per the instrumentation 6 5 settings, water will drain only after the water 4

drain % open value reaches 20%. During the DP psid 3 2 period between February–April in 2004,the sen- 1 sor collecting the data was not online, explain- 0 ing why the graph indicates a zero reading for 1/25/04 3/17/04 5/8/04 6/29/04 8/20/04 10/11/04 12/2/04 1/23/05 this period. The data over the year’s operation Figure 5: shows repeated valve opening indicating that Coalescer Differential Pressure the coalescer was effective in removing salt water contamination. The information regarding the prefilter differential pressure is presented in Figure 6. The pre- Figure 4: 80 filters are changed out after the differential Water Collection by 70 the High Efficiency 60 pressure reaches 20 psid, which is well below Coalescer System 50 their burst strength rating. The prefilter life was 40 initially shorter than expected and averaged about 30 20 2 weeks. Data was not being collected between

Water Drain % Open Water 10 February–March 2004 and the graph indicates 0

1/25/04 3/17/04 5/8/04 6/29/04 8/20/04 10/11/04 12/2/04 1/23/05 no readings during this period. The changes in the type of pre-filter and coalescer as well as the use of a settling tank locat- In Figure 5,the data on the coalescer differential ed onshore were implemented by July 2004.After pressure is presented. Initially,the AquaSep coa- these changes were made, the service life of the lescers were installed and the feed was directly pre-filters increased to about 2 months as indi- from the ship pipeline. The naphtha stream con- cated by Figure 6. tained higher than expected solids and this led to short coalescer life, which is illustrated by a 24 rapid rise in the differential pressure in early 22 20 February 2004 that was over 20 psid and off the 18 16 scale in Figure 5. 14 12

DP psid 10 The coalescers were then changed to the 8 6 PhaseSep coalescer, which is less sensitive to 4 solids loading.The feed was also changed from 2 0 the direct pipeline to an onshore settling tank in 1/25/04 3/17/04 5/8/04 6/29/04 8/20/04 10/11/04 12/2/04 1/23/05 July, 2004. Over the course of the rest of the Figure 6: year’s operation, the coalescer differential pres- Prefilter Differential Pressure sure increased gradually up to a maximum of

6 The naphtha flow rate can have a major impact ing the lowered flow rate period, the coalescer on the coalescer and prefilter performance, and did show frequent water drain valve opening in so this data is included in Figure 7. For the most April 2004 when the naphtha flow rate was part, the naphtha flow rate averaged between decreased. 60–67% of the rated design flow rate from May

2004 until January 2005. The flow rate had 90.0 dropped down to below 30% in March–April, 80.0 70.0 2004 and the initial flow rate in January–February, 60.0 2004 was a bit higher at around 60–80% of the 50.0 40.0 rated design.The operating flow rates have been 30.0 % Rated Flow below the rated design (100%) and the coalescer 20.0 10.0 has performed effectively throughout this peri- 0 1/25/04 3/17/04 5/8/04 6/29/04 8/20/04 10/11/04 12/2/04 1/23/05 od. Due to the mechanisms of diffusive capture and direct interception, the coalescer perform- Figure 7: ance is not affected by turndowns in the flow rate. Naphtha Flow Rate While not all of the data was being recorded dur-

Process Benefits

The primary benefit to the ethylene plant oper- The coalescer system also provided the follow- ation as a result of upgrading the fluid condi- ing additional process benefits for Dow: tioning of the feed naphtha was to extend the • Reduced fouling and plugging in the cracking run length of the furnaces due to reduced cok- coils ing. The furnace run lengths increased an aver- • Lowered fuel gas consumption due to less age of 33%.This led to a savings of $2.0 million fouling dollars per year due to the coalescer installation. • Improved control of the naphtha to steam The total capital plus installed cost of the coa- ratio due to reduced fouling of control valves lescer and filtration system was estimated at and flow meters $1.5 million dollars (with installation cost at • Reduced maintenance costs associated with 3-5 times the capital cost). The annual operating mechanical cleaning of the transfer line cost was calculated to be less than 10% of the exchangers capital plus installed cost of the system based on the coalescers lasting 2 years and the prefilters • Lengthened furnace tube life due to the use lasting 2 months. Using these calculations the of liquid-liquid coalescers,which helped elim- payback period due to furnace run time improve- inate the sodium attacks that drastically reduce ments alone is estimated at less than ten months the lifespan of the tubes assuming that ethylene production is limited due • Reduced CO formation and concentration in to furnace availability. the cracked gas

• Lowered particle and CO2 emissions due to less decoking operations in one year.

7 Conclusions

High efficiency liquid-liquid coalescers and filters between de-coking, increasing the useful life of used to treat liquid or gas hydrocarbon feeds in the furnace tubes,and the lowering of emissions. ethylene plants were found to increase the steam This technology also enables ethylene plants to cracker productivity and lower emissions by use more contaminated, alternate feed stocks decreasing the decoking frequency. In crackers such as naphtha brought in by marine transport fed with barged naphtha, the newly developed or Light Cat-cracked Naphtha (LCN/FCC gaso- liquid-liquid coalescers removed fouling and coke- line) coming from refineries. The payback peri- generating contaminants including sodium. Filters od for the capital investment in the high efficiency and coalescers successfully protected the fur- coalescer and pre-filter systems was estimated naces at Dow in Freeport,Texas. to be less than ten months assuming that ethyl- Major benefits of using high efficiency ene production is limited due to furnace avail- liquid–liquid coalescers and filters include the ability. The operating costs were found to be reduction of fouling in the cracking coils, the reasonable at less than 10% of the capital and extension of the run length of the furnaces installed cost of the coalescer-filter system.

References

1. Orriss, R., “Effects of Contaminants in Ethylene 6. Katona, A., Darde, T., Wines, T. H., “Improve Haze Plants:Sodium and Iron,”AIChE Conference,Spring Removal for FCC Gasoline,” Hydrocarbon Meeting, 1996. Processing, August 2001,Vol.80,No.8,pp.103-108. 2. Albright, L.F.,“Ethylene Tubes Studies,” Oil & Gas 7. Balouet,S.,Wines,T.H.,and Darde,T.“Contribution Journal, Aug. 1-1988, Aug.15-1988, August 1988. of Filtration and Coalescence to Steam Cracking 3. Darde, T., “Feed Filtering Requirements," Axens Furnace Productivity and Emissions Control,” Prime G+ customer seminar; November 2002. European Ethylene Producers Conference,Vienna, Austria, October 2004. 4. Brown, R. L., Wines, T. H., "Difficult Liquid-Liquid Separations," Chemical Engineering; December 1997,Vol. 72, No. 12, p. 95. 5. Hampton, P., Darde, T., James, R.H., Wines, T. H., “Liquid-Liquid Separation Technology Improves IFPEXOL Process Economics,”Oil & Gas Journal; April 2001.

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Bulletin No. GDS138 7/06 • 2M • ASP