Hydrocarbon Processing Refining Processes 2000[2]

8/9/2019 Hydrocarbon Processing Refining Processes 2000[2]

1/95

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Hydrocarbon Processing ®

Refining Processes 2000

AlkylationAlkylation feed preparation

Aromatics extractionAromatics extracted distillationAromatics recoveryBenzene reductionBenzene saturationCatalytic crackingCatalytic dewaxingCatalytic reforming

CokingCrude distillationDeasphaltingDeep catalytic cracking

Deep thermal conversionDelayed cokingDesulfurizationDewaxingElectric desalting

EthersFluid catalytic crackingGas oil hydrotreatmentGas treating—H2S removal

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2/95




GasificationGasoline desulfurization

Gasoline desulfurization, ultra-deepHydrocrackingHydrocracking, residueHydrocracking/hydrotreating—VGOHydrodearomatizationHydrodesulfurizationHydrodesulfurization—UDHDSHydrogenation

HydrotreatingHydrotreating—catalytic dewaxingHydrotreating—HDArHydrotreating—HDHDC

Hydrotreating, residueIso-octaneIsomerizationLube hydroprocessingLube treating

NOx abatementOily waste treatmentOlefins recoveryResid catalytic crackingResidue hydroprocessing

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3/95




Thermal gas oil process

Treating

Visbreaking

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4/95


5/95

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Chevron Research and Technology Co.Hydrocracking

HydrotreatingConoco Inc.

Desulfurization

ELFCrude distillation

ExxonMobil Research & Engineering Co.Alkylation

Catalytic dewaxing

Gas treating—H2S removal

Hydrotreating—catalytic dewaxingLube treating

NOx abatement

Oily waste treatment

Foster Wheeler USA Corp.Coking

Crude distillation

Deasphalting

Visbreaking

Fuels Technology Division of Phillips Petroleum Co.Alkylation

Gasoline desulfurization

Isomerization

GTC Technology Corp.Aromatics recovery

Desulfurization

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6/95




Haldor Topsøe A/SHydrodearomatization

HydrotreatingHowe-Baker Engineers, Inc.

Catalytic reforming

Electrical desalting

Hydrotreating

IFPBenzene reduction

Catalytic reforming

Fluid catalytic cracking

Gas oil hydrotreatment

Gasoline desulfurization, ultra-deep

Hydrocracking

Hydrocracking/hydrotreating—VGO

Hydrotreating, residue

Isomerization

Resid catalytic cracking

IFP North AmericaGasoline desulfurization, ultra-deep

Hydrocracking/hydrotreating—VGO

Imperial Petroleum Recovery Corp.Oily waste treatment

Kellogg Brown & Root, Inc.Deasphalting


Hydrocracking

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7/95




Kellogg Brown & Root, Inc. continuedHydrodesulfurization—UDHDS

Hydrotreating—HDHDCIso-octane

Isomerization

Krupp UhdeAromatics extractive distillation

Lyondell Chemical Co.Isomerization

Merichem Co.Treating

Neste Engineering OyIso-octane

Oxy Research & Development Co.Hydrocracking

Pro-Quip Corp.Olefins recovery

Research Institute of PetroleumDeep catalytic cracking

Shell Global Solutions International B.V.Crude distillation

Deep thermal conversion


Gasification

Hydrocracking

Hydrotreating

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8/95




Shell Global Solutions International B.V. continuedLube hydroprocessing

Residue hydroprocessingVisbreaking

Shell International Oil Products B.V.Thermal gasoil process

SK Corp.Lube treating

Snamprogetti SpAEthers

Iso-octane/iso-octene

Stone & Webster Inc., a Shaw Group Co.Deep catalytic crackingFluid catalytic cracking

Resid catalytic cracking

Stratco Inc.Alkylation

TECHNIPCrude distillation

UOP LLCAlkylation

Alkylation

Catalytic cracking

Catalytic reforming

Coking

Deasphalting


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9/95




UOP LLC continuedHydrocracking

HydrodesulfurizationHydrotreating

Hydrotreating

Isomerization

Visbreaking

VEBA OEL Technologie und Automatisierung GmbHHydrocracking

Washington Group InternationalLube treating

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10/95

Alkylation Application: Combines propylene, butylene and pentylene withisobutane, in the presence of sulfuric acid catalyst, to form a high-octane, mogas component.

Products: A highly isoparaffinic, low Rvp, high-octane gasolineblendstock is produced from the alkylation process.

Description: Olefin feed and recycled isobutane are introduced intothe stirred, autorefrigerated reactor (1). Mixers provide intimate con-tact between the reactants and the acid catalyst. Reaction heat isremoved from the reactor by the highly efficient autorefrigerationmethod. The hydrocarbons that are vaporized from the reactor, and thatprovide cooling to the 40°F level, are routed to the refrigeration com-pressor (2) where they are compressed, condensed and returned to thereactor. A depropanizer (3), which is fed by a slipstream from the refrig-eration section, is designed to remove any propane introduced to the

plant with the feeds. The reactor product is sent to the settler (4), wherethe hydrocarbons are separated from the acid that is recycled. Thehydrocarbons are then sent to the deisobutanizer (5) along withmakeup isobutane. The isobutane-rich overhead is recycled to thereactor. The bottoms are then sent to a debutanizer (6) to produce alow Rvp alkylate product with an FBP less than 400°F.

Major features of the reactor are:• Use of the autorefrigeration method of cooling is thermodynamically

efficient. It also allows lower temperatures, which are favorable for pro-ducing high product quality with low power requirements.

• Use of a staged reactor system results in a high average isobu-tane concentration, which favors high product quality.

• Use of low space velocity in the reactor design results in high prod-uct quality and eliminates any corrosion problems in the fractiona-tion section associated with the formation of esters.

• Use of low reactor operating pressure means high reliability forthe mechanical seals for the mixers.

• Use of simple reactor internals translates to low cost.

Yields: Alkylate yield 1.78 bbl C5

+ /bbl butylene feedIsobutane (pure) required 1.17 bbl/bbl butylene feed

Alkylate quality 96 RON/94 MON

Economics:Utilities, typical per barrel of alkylate produced:Water, cooling (20°F rise), 1,000 gal 2.1Power, kWh 10.5

Steam, 60 psig, lb 200H2SO4, lb 19NaOH, 100%, lb 0.1

Installation: 100,000-bpd capacity at nine locations with the sizesranging from 2,000 to 30,000 bpd. Single reactor/settle trains withcapacities up to 89,000 bpd.

Reference: Lerner, H., “Exxon sulfuric acid alkylation technol-ogy,” Handbook of Petroleum Refining Processes,2nd Ed., R. A. Mey-ers, ed., pp. 1.3–1.14.

Licensor: ExxonMobil Research & Engineering Co.

Alkylateproduct

Butaneproduct

Olefinfeed

Recycle acid Makeupisobutane

Propane product

RecycleisobutaneRefrigerant

14

5 6

32

START

REFINING PROCESSES 2000

Copyright © 2001 by Gulf Publishing Company. All rights reserved.back to main menu


11/95

Alkylation Application: Convert propylene, amylenes, butylenes and isobutaneto the highest quality motor fuel using ReVAP alkylation.

Products: An ultra-low-sulfur, high-octane and low-RVP blending

stock for motor and aviation fuels.Description: Dry liquid feed containing olefins and isobutane ischarged to a combined reactor-settler (1). The reactor uses the prin-ciple of differential gravity head to effect catalyst circulation througha cooler prior to contacting highly dispersed hydrocarbon in thereactor pipe. The hydrocarbon phase that is produced in the settleris fed to the main fractionator (2), which separates LPG-qualitypropane, isobutane recycle, n-butane and alkylate products. Smallamount of dissolved catalyst is removed from the propane productby a small stripper tower (3). Major process features are:

• Gravity catalyst circulation (no catalyst circulation pumps

required)• Low catalyst consumption• Low operating cost• Superior alkylate qualities from propylene, isobutylene and

amylene feedstocks• Onsite catalyst regeneration• Environmentally responsible (very low emissions/waste)• Between 60%–90% reduction in airborne catalyst release over

traditional catalysts• Can be installed in all licensors’ HF alkylation units.With the proposed reduction of MTBE in gasoline, ReVAP offers

significant advantages over sending the isobutylene to a sulfuric-acid-alkylation unit or a dimerization plant. ReVAP alkylation pro-duces higher octane, lower RVP and endpoint product than a sulfu-ric-acid-alkylation unit and nearly twice as many octane barrels as

can be produced from a dimerization unit.

Yields: Feed typeButylene Propylene-butylene mix

Composition (lv%)Propylene 0.8 24.6Propane 1.5 12.5Butylene 47.0 30.3i-Butane 33.8 21.8n-Butane 14.7 9.5i-Pentane 2.2 1.3

Alkylate product

Gravity, API 70.1 71.1RVP, psi 6–7 6–7

ASTM 10%, °F 185 170 ASTM 90%, °F 236 253RONC 96.0 93.5

Per bbl olefin convertedi-Butane consumed, bbl 1.139 1.175

Alkylate produced, bbl 1.780 1.755

Installation: 107 alkylation units licensed worldwide.

Licensor: Fuels Technology Division of Phillips Petroleum Co.

Isobutane recycle

1

2

3

Olefin feed

Isobutane

Motor fuel butane

Alkylate

Propane

START

START




12/95

Alkylation Application: To combine propylene, butylenes and amylenes withisobutane in the presence of strong sulfuric acid to produce high-octane branched chain hydrocarbons using the Effluent Refrigera-tion Alkylation process.

Products: Branched chain hydrocarbons for use in high-octanemotor fuel and aviation gasoline.

Description: Plants are designed to process a mixture of propylene,butylenes and amylenes. Olefins and isobutane-rich streams along with a recycle stream of H2SO4 are charged to the Contactor (1). Theliquid contents of the Contactor are circulated at high velocities

and an extremely large amount of interfacial area is exposed betweenthe reacting hydrocarbons and the acid catalyst from the acid settler(2). The entire volume of the liquid in the Contactor is maintainedat a uniform temperature, less than 1°F between any two points

within the reaction mass. Reactor products pass through a flash drum(3) and deisobutanizer (4). The refrigeration section consists of a com-pressor (5) and depropanizer (6).

The overhead from the deisobutanizer (4) and effluent refrigerantrecycle (6) constitutes the total isobutane recycle to the reactionzone. This total quantity of isobutane and all other hydrocarbons ismaintained in the liquid phase throughout the Contactor, therebyserving to promote the alkylation reaction. Onsite acid regenerationtechnology is also available.

Product quality: The total debutanized alkylate has RON of 92 to

96 clear and MON of 90 to 94 clear. When processing straightbutylenes, the debutanized total alkylate has RON as high as 98 clear.Endpoint of the total alkylate from straight butylene feeds is less than390°F and less than 420°F for mixed feeds containing amylenes inmost cases.

Economics (basis: butylene feed):Investment (basis: 10,000-bpsd unit), $ per bpsd 3,500Utilities, typical per bbl alkylate:Electricity, kWh 13.5Steam, 150 psig, lb 180Water, cooling (20oF rise), 103 gal 1.85

Acid, lb 15Caustic, lb 0.1

Installation: Nearly 600,000 bpsd installed capacity.

Reference: Hydrocarbon Processing, Vol. 64, No. 9, September1985, pp. 67–71.

Licensor: Stratco, Inc.

Olefin feed

6

i-Butane

3

5

1

2

Propaneproduct

4

n-Butaneproduct

Alkylateproduct

START

START




13/95

Alkylation Application: The Alkylene process uses a solid catalyst to react isobu-tane with light olefins (C3 to C5) to produce a branched-chain paraf-finic fuel. The performance characteristics of this catalyst and novelprocess design have yielded a technology that is competitive with tra-

ditional liquid-acid-alkylation processes. Unlike liquid-acid-cat-alyzed technologies, significant opportunities to continually advancethe catalytic activity and selectivity of this exciting new technologyare possible. This process meets today’s demand for both improvedgasoline formulations and a more “environmentally friendly” lightolefin upgrading technology.

Description: Olefin charge is first treated to remove impurities suchas diolefins and oxygenates (1). The olefin feed and isobutane recy-cle are mixed with reactivated catalyst at the bottom of the reactorvessel riser (2). The reactants and catalyst flow up the riser in a cocur-

rent manner where the alkylation reaction occurs. Upon exiting theriser, the catalyst separates easily from the hydrocarbon effluent liq-uid by gravity and flows downward into the cold reactivation zoneof the reactor. The hydrocarbon effluent flows to the fractionation sec-tion (3), where the alkylate product is separated from the LPG prod-uct. There is no acid soluble oil (ASO) or heavy polymer to disposeof as with liquid acid technology.

The catalyst flows slowly down the annulus section of the reactoraround the riser as a packed bed. Isobutane saturated with hydrogenis injected to reactivate the catalyst. The reactivated catalyst thenflows through standpipes back into the bottom of the riser. The reac-

tivation in this section is nearly complete, but some strongly adsorbedmaterial remains on the catalyst surface. This is removed by process-ing a small portion of the circulating catalyst in the reactivation ves-sel (4), where the temperature is elevated for complete reactivation. Thereactivated catalyst then flows back to the bottom of the riser.

Product quality: Alkylate has ideal gasoline properties such as: highresearch and motor octane numbers, low Reid vapor pressure (Rvp),and no aromatics, olefins or sulfur. The alkylate from an Alkyleneunit has the particular advantage of lower 50% and 90% distillationtemperatures, which is important for new reformulated gasolinespecifications.

Economics: (basis: FCC source C4 olefin feed)Investment (basis: 6,000-bpsd unit), $ per bpsd 4,940Operating cost ($/gal) 0.54

Licensor: UOP LLC.

Light ends

Alkylate

LPG

42

1

Olefin feed

i -C4 /H2

i -C4 /H2

Isobutane recycle

3




14/95

Alkylation Application: The UOP Indirect Alkylation (InAlk) process usessolid catalysts to react isobutylene with light olefins (C3 to C5) to pro-duce a high-octane, low-vapor pressure, paraffinic gasoline compo-nent similar in quality to traditional motor alkylate.

Description: The InAlk process combines two, commercially proventechnologies: polymerization and olefin saturation. Isobutylene isreacted with light olefins (C3 to C5) in the polymerization reactor (1).The resulting mixture of iso-olefins is saturated in the hydrogena-tion reactor (2). Recycle hydrogen is removed (3) and the product is

stabilized (4) to produce a paraffinic gasoline componentThe InAlk process is more flexible than the traditional alkyla-

tion processes. Using a direct alkylation process, refiners must matchthe isobutane requirement with olefin availability. The InAlk pro-

cess does not require a set amount of isobutane to produce a high-quality product. Additional flexibility comes from being able to revampexisting catalytic condensation and MTBE units easily to the InAlkprocess.

The flexibility of the InAlk process is in both the polymerizationand hydrogenation sections. Both sections have different catalystoptions based on specific operating objectives and site conditions.This flexibility allows existing catalytic condensation units to revampto the InAlk process with the addition of the hydrogenation sectionand optimized processing conditions. Existing MTBE units can beconverted to the InAlk process with only minor modifications.

Product quality: High octane (99 RON, 94 MON), low Rvp, mid-boil-ing-range paraffinic gasoline blending component with no aromaticcontent, low-sulfur content and adjustable olefin content.

Economics: (basis: C4 feed from FCC unit)

Investment (basis: 2,800-bpsd unit), $ / bpsdGrassroots 3,000Revamp of MTBE unit 1,580

Utilities (per bbl InAlkylate)Hydrogen, lb 4.3Power, kW 2.1HP steam, lb 65LP steam, lb 33

Licensor: UOP LLC.

Offgas

LPG

Alkylate

5

3

1 2 4

Olefinfeed

Makeup H2




15/95

Alkylation feed preparation Application: Upgrades alkylation plant feeds with Alkyfining process.

Description: Diolefins and acetylenes in the C4 (or C3–C4) feedreact selectively with hydrogen in the liquid-phase, fixed-bed reac-

tor under mild temperature and pressure conditions. Butadieneand, if C3s are present, methylacetylene and propadiene are convertedto olefins.

The high isomerization activity of the catalyst transforms 1-buteneinto cis- and trans-2-butenes, which affords higher octane-barrelproduction.

Good hydrogen distribution and reactor design eliminate channeling

while enabling high turndown ratios. Butene yields are maximized,hydrogen is completely consumed, and essentially no gaseous byprod-ucts or heavier compounds are formed. Additional savings are pos-sible when pure hydrogen is available eliminating the need for a sta-

bilizer. The process integrates easily with the C3 /C4 splitter. Alkyfining performance and impact on HF alkylation

product: The table below shows the results of an Alkyf ining unittreating an FCC C4-HF-alkylation unit feed containing 0.8% 1,3-butadiene.

Butadiene in alkylate, ppm


16/95

Aromatics extraction Application: Simultaneous recovery of benzene, toluene and xylenes(BTX) from reformate or pyrolysis gasoline (pygas) using liquid-liq-uid extraction.

Description: At the top of extractor operating at 30°C to 50°C and1 to 3 bar, the solvent, N-Formylmorpholin with 4% to 6% water, isfed as a continuous phase. The feedstock—reformate or pygas—enters several stages above the base of the column. Due to densitydifferences, the feedstock bubbles upwards, countercurrent to the sol-vent. Aromatics pass into the solvent, while the nonaromatics moveto the top, remaining in the light phase. Low-boiling nonaromatics

from the top of the extractive distillation (ED) column enter the baseof the extractor as countersolvent.

Aromatics and solvent from the bottom of the extractor enter theED, which is operated at reduced pressure due to the boiling-tem-

perature threshold. Additional solvent is fed above the aromaticsfeed containing small amounts of nonaromatics that move to the topof the column. In the bottom section as well as in the side rectifier aro-matics and practically water-free solvent are separated.

The water is produced as a second subphase in the reflux drumafter azeotropic distillation in the top section of the ED. This wateris then fed to the solvent-recovery stage of the extraction process.

Economics:Consumption per ton of feedstock

Steam (20 bar), t/t 0.46

Water, cooling (T=10ºC), m3

/t 12Electric power, kWh/t 18Production yield

Benzene, % ~100Toluene, % 99.7EB, Xylenes,% 94.0

Purity Benzene, wt% 99.999Toluene, wt% >99.99EB, Xylenes, wt% >99.99

Installation: One Morphylane plant was erected.

Reference: Emmrich, G., F. Ennenbach, and U. Ranke, “Krupp UhdeProcesses for Aromatics Recovery,” European Petrochemical Tech-nology Conference, June 21–22, 1999, London.

Licensor: Krupp Uhde.

Nonaromatics

AromaticsSide

stripper

Light nonaromatics

Extractive

distillationcolumn

Water

Water

Feed BTX-fraction

Extractor

Washer

Water &solvent




17/95

Aromatics extractivedistillation Application: Recovery of high-purity aromatics from reformate,pyrolysis gasoline or coke-oven light oil using extractive distillation.

Description: In the extractive distillation (ED) process, a single-com-pound solvent, N-Formylmorpholin (NFM) alters the vapor pressureof the components being separated. The vapor pressure of the aro-matics is lowered more than that of the less soluble nonaromatics.

Nonaromatics vapors leave the top of the ED column with somesolvent, which is recovered in a small column that can either be

mounted on the main column or installed separately.Bottom product of the ED column is fed to the stripper to separate

pure aromatics from the solvent. After intensive heat exchange, thelean solvent is recycled to the ED column. NFM perfectly satisfies

the necessary solvent properties needed for this process including high selectivity, thermal stability and a suitable boiling point.

Economics:Pygas feedstock:

Benzene Benzene/tolueneProduction yield

Benzene 99.95% 99.95%Toluene – 99.98%

Quality Benzene 30 wt ppm NA* 80 wt ppm NA*

Toluene – 600 wt ppm NA*ConsumptionSteam 475 kg/t ED feed 680 kg/t ED feed**

Reformate feedstock with low aromatics content (20wt%):Benzene

Quality Benzene 10 wt ppm NA*

ConsumptionSteam 320 kg/t ED feed

*Maximum content of nonaromatics.**Including benzene/toluene splitter.

Installation: 45 plants (total capacity of more than 6 MMtpa).

Reference: Emmrich, G., F. Ennenbach, and U. Ranke, “KruppUhde Processes for Aromatics Recovery,” European PetrochemicalTechnology Conference, June 21–22, 1999, London.

Licensor: Krupp Uhde.

Nonaromatics

Aromatics

Extractivedistillation

column

Strippercolumn

Aromaticsfraction

Solvent Solvent+aromatics




18/95

Aromatics recovery Application: GT-BTX is an aromatics recovery process. The technologyuses extractive distillation to remove benzene, toluene and xylene (BTX)from refinery or petrochemical aromatics streams such as catalytic refor-mate or pyrolysis gasoline. The process is superior to conventional liquid-

liquid extraction processes in terms of lower capital and operating costs,simplicity of operation, range of feedstock and solvent performance. Flex-ibility of design allows its use for grassroots aromatics recovery units, debot-tlenecking or expansion of conventional extraction systems.

Description: The technology has several advantages:• Less equipment required, thus, significantly lower capital cost

compared to conventional liquid-liquid extraction systems• Energy integration reduces operating costs• Higher product purity and aromatic recovery• Recovers aromatics from full-range BTX feedstock without pre-

fractionation• Distillation-based operation provides better control and sim-

plified operation• Proprietary formulation of commercially available solvents

exhibits high selectivity and capacity• Low solvent circulation rates• Insignificant fouling due to elimination of liquid-liquid

contactors• Fewer hydrocarbon emission sources for environmental benefits• Flexibility of design options for grassroots plants or expansion

of existing liquid-liquid extraction units.Hydrocarbon feed is preheated with hot circulating solvent and fed

at a midpoint into the extractive distillation column (EDC). Lean solventis fed at an upper point to selectively extract the aromatics into the col-umn bottoms in a vapor/liquid distillation operation. The nonaromatic

hydrocarbons exit the top of the column and pass through a condenser. A portion of the overhead stream is returned to the top of the column asreflux to wash out any entrained solvent. The balance of the overheadstream is the raffinate product, requiring no further treatment.

Rich solvent from the bottom of the EDC is routed to the solvent-recovery column (SRC), where the aromatics are stripped overhead.Stripping steam from a closed-loop water circuit facilitates hydro-carbon removal. The SRC is operated under a vacuum to reduce theboiling point at the base of the column. Lean solvent from the bottomof the SRC is passed through heat exchange before returning to theEDC. A small portion of the lean circulating solvent is processed in a

solvent-regeneration step to remove heavy decomposition products.The SRC overhead mixed aromatics product is routed to the purifi-cation section, where it is fractionated to produce chemical-gradebenzene, toluene and xylenes.

Economics: Estimated installed cost for a 15,000-bpd GT-BTX extraction unit processing BT-Reformate feedstock is $12 million (U.S.Gulf Coast 2000 basis).

Installations: Three grassroots applications.

Licensor: GTC Technology Corp.

Hydrocarbonfeed

START

Lean solvent

Aromatics-rich solvent

Aromatics todownstreamfractionation

Steam

WaterRaffinate

Solventrecovery

column

Extractivedistillationcolumn

1

2




19/95

Benzene reduction Application: Benzene reduction from reformate, with the Benfreeprocess, using integrated reactive distillation.

Description: Full-range reformate from either a semiregenerative

or CCR reformer is fed to the reformate splitter column, shownabove. The splitter operates as a dehexanizer lifting C6 and lower-boiling components to the overhead section of the column. Benzeneis lifted with the light ends, but toluene is not. Since benzene formsazeotropic mixtures with some C7 paraffin isomers, these fractionsare also entrained with the light fraction.

Above the feed injection tray, a benzene-rich light fraction is with-drawn and pumped to the hydrogenation reactor outside the column. A pump enables the reactor to operate at higher pressure than thecolumn, thus ensuring increased solubility of hydrogen in the feed.

A slightly higher-than-chemical stoichiometric ratio of hydrogento benzene is added to the feed to ensure that the benzene contentof the resulting gasoline pool is below mandated levels, i.e., below 1.0vol% for many major markets. The low hydrogen flow minimizeslosses of gasoline product in the offgas of the column. Benzene con-version to cyclohexane can easily be increased if even lower benzenecontent is desired. The reactor effluent, essentially benzene-free, isreturned to the column.

The absence of benzene disrupts the benzene-iso-C7 azeotropes,thereby ensuring that the latter components leave with the bot-toms fraction of the column. This is particularly advantageous when

the light reformate is destined to be isomerized, because iso-C7paraffins tend to be cracked to C3 and C4 components, thus leading to a loss of gasoline production.

Economics:Investment: Grassroots ISBL cost: 300 $/bpsdCombined utilities: 0.17 $/bblHydrogen: Stoichiometric to benzeneCatalyst: 0.01 $/bbl

Installation: Eight benzene reduction units have been licensed.

Reference: “The Domino Interaction of Refinery Processes forGasoline Quality Attainment,” NPRA Annual Meeting, March 26–28,2000, San Antonio.

Licensor: IFP.

C5-C9Reformate H2

Splitter

Offgas

Heavy

reformate

Lightreformate

C5 /C6




20/95

Benzene saturation Application: Remove benzene from light reformate or light straight-run naphtha streams to meet benzene specifications in the gasolinepool. Benzene is saturated to cyclohexane at high selectivity. This sat-uration can be achieved either in a stand-alone option or in combi-

nation with isomerization to upgrade the octane.The BenSat process is a stand-alone option to treat C5-C6 feedstocks

that are high in benzene. Benzene is completely saturated to cyclo-hexane in the presence of hydrogen.

The Penex-Plus process integrates the isomerization features of the

Penex process with benzene saturation for high-benzene feedstocks.Complete benzene saturation is achieved while maintaining thedesired C5 and C6 isomerization reactions for octane upgrading.

Benzene levels in Penex-Plus and BenSat feedstocks range from

a few percent to 30 vol% or more.

Description: Both the BenSat and Penex-Plus processes use anoble metal catalyst developed by UOP. The heat of reaction asso-ciated with benzene saturation is carefully managed to control thetemperature rise. The BenSat process is preferred when no octaneupgrade is required. The Penex-Plus process is chosen when anoctane increase is required.

The accompanying flow diagram represents the BenSat process.Feed is heated (1) against reactor effluent, mixed with makeuphydrogen and sent to the benzene saturation reactor section (2).

Reactor effluent is sent to the stabilizer (3) after heat exchange. Sta-bilizer bottoms are sent to gasoline blending and light ends are sentto fuel gas.

Economics:Investment (basis: 2nd Quarter 2000, U.S. Gulf Coast)Operation BenSat Penex-PlusSize basis, bpsd 10,000 15,000Benzene basis, lv% 20 7$ per bpsd 555 795

Installation: The BenSat and Penex-Plus processes were first

offered for license in 1991. Four Penex-Plus units and three BenSatunits are in operation.

Reference: AIChE meeting, New Orleans, Louisiana, April 1992.

Licensor: UOP LLC.

START

1

2

3

Product

Light end to FG

Feedeffluent

exchanger

Preheater(for startup only)

Makeup hydrogen

Feed




21/95

Catalytic cracking Application: To selectively convert gas oils and residual feedstocksto higher-value cracked products such as light olef ins, gasoline anddistillates.

Description: The Milli-Second Catalytic Cracking (MSCC) processuses a fluid catalyst and a novel contacting arrangement to crackheavier materials into a highly selective yield of light olefins, gaso-line and distillates. A distinguishing feature of the process is that the

initial contact of oil and catalyst occurs without a riser in a very shortresidence time followed by a rapid separation of initial reactionproducts. Because there is no riser and the catalyst is downflowing,startup and operability are outstanding.

The configuration of an MSCC unit has the regenerator (1) at ahigher elevation than the reactor (2). Regenerated catalyst falls downa standpipe (3), through a shaped opening (4) that creates a falling curtain of catalyst, and across a well-distributed feed stream. Manyproducts from this initial reaction are quickly separated from thecatalyst. The catalyst then passes into a second higher-temperaturereaction zone (5), where further reaction and stripping occurs. Thehigher temperature is achieved through contact with regeneratedcatalyst.

Since a large portion of the reaction product is produced undervery short time conditions, the reaction mixture maintains good prod-

uct olefinicity and retains hydrogen content in the heavier liquidproducts. Additional reaction time is available for the more-difficult-to-crack species in the second reaction zone/stripper.

Stripped catalyst is airlifted back to the regenerator where cokedeposits are burned, creating clean, hot catalyst to begin the sequenceagain.

Installations: A new MSCC unit began operation earlier this year,and a revamped MSCC unit has been in operation since 1994. Twoadditional MSCC facilities are in design and construction.

Reference: “Short-Contact-Time FCC,” AIChE 1998 Spring Meet-

ing, New Orleans.

Licensor: UOP LLC (in cooperation with BARCO).

FeedMSCC reactor

Regenerator

3

42

1

5




22/95

Catalytic dewaxing Application: Use the ExxonMobil Selective Catalytic Dewaxing (MSDW) process to make high VI lube base stock.

Products: High VI/low-aromatics lube base oils (light neutral

through bright stocks). Byproducts include fuel gas, naphtha and low-pour diesel.

Description: MSDW is targeted for hydrocracked or severely

hydrotreated stocks. The improved selectivity of MSDW for thehighly isoparaffinic-lube components, which results in higher lubeyields and VI’s. The process uses multiple catalyst systems with mul-tiple reactors. Internals are proprietary (the Spider Vortex Quench

Zone technology is used). Feed and recycle gases are preheated andcontact the catalyst in a down-flow-fixed-bed reactor. Reactor efflu-ent is cooled, and the remaining aromatics are saturated in a post-treat reactor. The process can be integrated into a lube hydrocrackeror lube hydrotreater. Postfractionation is targeted for client needs.

Operating conditions:Temperatures, °F 550 to 800Hydrogen partial pressures, psig 500 to 2,500LHSV 0.4 to 3.0Conversion depends on feed wax content

Pour point reduction as needed. Yields:

Light neutral Heavy neutralLube yield, wt% 94.5 96.5C1 to C4, wt% 1.5 1.0C5–400°F, wt% 2.7 1.8400°F–Lube, wt% 1.5 1.0H2 cons,scf/bbl 100–300 100–300

Economics: $3,000–5,500 per bpsd installed cost (U. S. Gulf Coast).

Installation: Three units are operating, one under constructionand one being converted.

Licensor: ExxonMobil Research & Engineering Co.

Waxyfeed

Lube product

HDTRxr

HDWRxr

Purge

HP stripper

MP steam

Oily water

LTsepHT

sep

Water

M/U

Rec

Fuel ags to LP absorber

Wild naphtha

Sour water

Sour water

Distillate

Vacuum system

MakeupH2

MP steamVacdryer

Vacstrip.

Water wash

Water

wash




23/95

Catalytic reforming Application: Increase the octane of straight run or cracked naph-thas for gasoline production.

Products: High-octane gasoline and hydrogen-rich gas. Byprod-ucts may be LPG, fuel gas and steam.

Description: Semi-regenerative multibed reforming over platinumor bimetallic catalysts. Hydrogen recycled to reactors at the rate of

3 to 7 mols/mol of feed. Straight run and/or cracked feeds are typi-cally hydrotreated, but low-sulfur feeds (


24/95

Catalytic reforming Application: Upgrade various types of naphtha to produce high-octane reformate, BTX and LPG.

Description: Two different designs are offered. One design is con-ventional where the catalyst is regenerated in place at the end of each

cycle. Operating normally in a pressure range of 12 to 25 kg/cm2 (170to 350 psig) and with low pressure drop in the hydrogen loop, the prod-uct is 90 to 100 RONC. With its higher selectivity, trimetallic cata-lyst RG582 makes an excellent catalyst replacement for semi-regen-erative reformers.

The second, the advanced Octanizing process, uses continuouscatalyst regeneration allowing operating pressures as low as 3.5kg/cm2 (50 psig). This is made possible by smooth-flowing moving bedreactors (1–4) which use a highly stable and selective catalyst suit-able for continuous regeneration (5). Main features of IFP’s regen-erative technology are:

• Side-by-side reactor arrangement, which is very easy to erect andconsequently leads to low investment cost.

• The Regen C catalyst regeneration system featuring the dry burnloop, completely restores the catalyst activity while maintaining its

specific area for more than 600 cycles.Finally, with the new CR401 (gasoline mode) and AR501 (aromat-

ics production) catalysts specifically developed for ultra-low operating pressure and the very effective catalyst regeneration system, refinersoperating Octanizing or Aromizing processes can obtain the highesthydrogen, C5

+ and aromatics yields over the entire catalyst life.

Yields: Typical for a 90°C to 170°C (176°F to 338°F) cut from light Arabian feedstock:

Conventional OctanizingOper. press., kg/cm2 10–15


25/95

Catalytic reforming Application: Upgrade naphtha for use as a gasoline blendstock orfeed to a petrochemical complex with the UOP CCR Platforming pro-cess. The unit is also a reliable, continuous source of high-purityhydrogen.

Description: Constant product yields and onstream availabilitydistinguish the CCR Platforming process featuring catalyst transferwith minimum lifts, no valves closing on catalyst and gravity flowfrom reactor to reactor (2,3,4). The CycleMax regenerator (1) providessimplified operation and enhanced performance at a lower cost thanother designs. The product recovery section downstream of the sep-arator (7) is customized to meet site-specific requirements. The R-270 series catalysts offer the highest C5

+ and hydrogen yields whilealso providing the R-230 series attributes of CCR Platforming pro-cess unit flexibility through reduced coke make.

Semiregenerative reforming units also benefit from the latest UOPcatalysts. The R-72 staged loading system provides the highest C5+yields available. Refiners use UOP engineering and technical serviceexperience to tune operations, plan the most cost-effective revamps,

and implement a stepwise approach for conversion of semiregenera-tive units to obtain the full benefits of CCR Platforming technology.

Yields:Operating mode Semiregen. ContinuousOnstream availability, days/yr 330 360Feedstock, P/N/A LV% 63/25/12 63/25/12IBP/EP,°F 200/360 200/360

Operating conditionsReactor pressure, psig 200 50C5

+ octane, RONC 100 100

Catalyst R-72 staged loading R-274 Yield informationHydrogen, scfb 1,270 1,690C5

+, wt% 85.3 91.6

Economics:Investment (basis: 20,000 bpsd CCR Platforming unit, 50 psig reac-tor pressure, 100 C5

+ RONC, 2000, U.S. Gulf Coast ISBL):$ per bpsd 2,000

Installation: UOP has licensed more than 800 platforming units; 37customers operate 2 or more CCR Platformers. Twenty-six refiners

operate 90 of the 163 operating units. Twenty units are designed forinitial semiregenerative operation with the future installation of aCCR regeneration section.

Operating Design & const.Total CCR Platforming units 163 41Ultra-low 50 psig units 40 27Units at 35,000+ bpsd 29 4Semiregenerative units

with a stacked reactor 14 5

Licensor: UOP LLC.

START

Charge

Spent catalyst

To fractionator

Net gas toH2 users

Net gas to fuel

54

3

2

1 6 7




26/95

Coking Appl icat ion : Conversion of vacuum residues (virgin andhydrotreated), various petroleum tars and coal tar pitch throughdelayed coking.

Products: Fuel gas, LPG, naphtha, gas oils and fuel, anode or nee-dle grade coke (depending on feedstock and operating conditions).

Description: Feedstock is introduced (after heat exchange) to thebottom of the coker fractionator (1) where it mixes with condensedrecycle. The mixture is pumped through the coker heater (2) wherethe desired coking temperature is achieved, to one of two coke drums(3). Steam or boiler feedwater is injected into the heater tubes to pre-vent coking in the furnace tubes. Coke drum overhead vapors flowto the fractionator (1) where they are separated into an overheadstream containing the wet gas, LPG and naphtha; two gas oilsidestreams; and the recycle that rejoins the feed.

The overhead stream is sent to a vapor recovery unit (4) where theindividual product streams are separated. The coke that forms in oneof at least two (parallel connected) drums is then removed using high-pressure water. The plant also includes a blow-down system, coke han-

dling and a water recovery system.

Operating conditions:Heater outlet temperature, °F 900–950Coke drum pressure, psig 15–90Recycle ratio, vol/vol feed, % 0–100

Yields: Vacuum residue of

Middle East hydrotreated Coal tarFeedstock vac. residue bottoms pitch

Gravity, °API 7.4 1.3 11.0Sulfur, wt% 4.2 2.3 0.5Conradson

carbon, wt% 20.0 27.6 —Products, wt%Gas + LPG 7.9 9.0 3.9Naphtha 12.6 11.1 —Gas oils 50.8 44.0 31.0Coke 28.7 35.9 65.1

Economics:Investment (basis: 20,000 bpsd straight run vacuum residue feed,

U.S. Gulf Coast 2000, fuel-grade coke, includes vapor recovery),U.S. $ per bpsd (typical) 4,000Utilities, typical/bbl of feed:Fuel, 103 Btu 145Electricity, kWh 3.9Steam (exported), lb 20Water, cooling, gal 180

Installation: More than 55 units.

Licensor: ABB Lummus Global Inc.

Fuel gas

C3 /C4 LP

Coker naphtha

START

1

2Light gas oil

Heavy gas oil

BFWStm.

Stm.

Stm.

BFW

Fresh feed

3 34




27/95


28/95

.

Crude distillation Application: The D2000 process is progressive distillation to min-imize the total energy consumption required to separate crude oilsor condensates into hydrocarbon cuts, which number and propertiesare optimized to fit with sophisticated refining schemes and future

regulations. This process is applied normally for new topping unitsor new integrated topping / vacuum units but the concept can be usedfor debottlenecking purpose.

Products: This process is particularly suitable when more than twonaphtha cuts are to be produced. Typically the process is optimizedto produce three naphtha cuts or more, one or two kerosine cuts, twoatmospheric gas oil cuts, one vacuum gas oil cut, two vacuum dis-tillates cuts, and one vacuum residue.

Description: The crude is preheated and desalted (1). It is fed to afirst dry reboiled pre-flash tower (2) and then to a wet pre-flash tower

(3). The overhead products of the two pre-flash towers are thenfractionated as required in a gas plant and rectification towers (4).

The topped crude typically reduced by 2 ⁄ 3 of the total naphtha cutis then heated in a conventional heater and conventional topping col-

umn (5). If necessary the reduced crude is fractionated in one deepvacuum column designed for a sharp fractionation between vacuumgas oil, two vacuum distillates (6) and a vacuum residue, whichcould be also a road bitumen.

Extensive use of pinch technology minimizes heat supplied byheaters and heat removed by air and water coolers.

This process is particularly suitable for large crude capacity from150,000 to 250,000 bpsd.

It is also available for condensates and light crudes progressivedistillation with a slightly adapted scheme.

Economics:

Investment (basis 230,000 bpsd including atmospheric andvacuum distillation, gas plant and rectification tower) 750 to950 $ per bpsd (U.S. Gulf Coast 2000).Utility requirements, typical per bbl of crude feed:

Fuel fired, 103 btu 50–65Power, kWh 0.9–1.2Steam 65 psig, lb 0–5Water cooling, (15°C rise) gal 50–100

Total primary energy consumption:

for Arabian Light or Russian

Export Blend: 1.25 tons of fuelper 100 tons of Crude

for Arabian Heavy 1.15 tons of fuelper 100 tons of Crude

Installation: Technip has designed and constructed one crude unitand one condensate unit with the D2000 concept. The latest revampproject currently in operation shows an increase of capacity of theexisting crude unit of 30% without heater addition.

Licensors: ELF and TECHNIP.

2 3

4

1

5

6

Feed

START

LPG

Light naphtha

Medium naphtha

Heavy naphtha

Distillate for FCC

Vacuum residue

Distillate

Vacuum gas oil

Two kerosine cut

One or two kerosine cutStm.




29/95

Crude distillation Application: Separates and recovers the relatively lighter frac-tions from a fresh crude oil charge (e.g., naphtha, kerosine, diesel andcracking stock). The vacuum flasher processes the crude distillationbottoms to produce an increased yield of liquid distillates and a

heavy residual material.Description: The charge is preheated (1), desalted (2) and directedto a preheat train (3) where it recovers heat from product and refluxstreams. The typical crude fired heater (4) inlet temperature is onthe order of 550°F, while the outlet temperature is on the order of 675°F to 725°F. Heater effluent then enters a crude distillation col-umn (5) where light naphtha is drawn off the tower overhead (6);heavy naphtha, kerosine, diesel and cracking stock are sidestreamdrawoffs. External reflux for the tower is provided by pumparoundstreams (7–10). The atmospheric residue is charged to a fired heater

(11) where the typical outlet temperature is on the order of 750°F to775°F.

From the heater outlet, the stream is fed into a vacuum tower (12),where the distillate is condensed in two sections and withdrawn as

two sidestreams. The two sidestreams are combined to form crack-ing feedstock. An asphalt base stock is pumped from the bottom of the tower. Two circulating reflux streams serve as heat removalmedia for the tower.

Yields: Typical for Merey crude oil:wt% °API Pour, °F

Crude unit productsOverhead & naphtha 6.2 58.0 —Kerosine 4.5 41.4 485Diesel 18.0 30.0 410Gas oil 3.9 24.0 20Lt. vac. gas oil 2.6 23.4 35Hvy. vac. gas oil 10.9 19.5 85

Vac. bottoms 53.9 5.8 ( 120 )*Total 100.00 8.7 85

*Softening point, °FNote: Crude unit feed is 2.19 wt% sulfur. Vacuum unit feed is 2.91 wt% sulfur.

Economics:Investment (basis: 100,000–50,000 bpsd, 4th Q, 1999, U.S. Gulf),$ per bpsd 850–1,050Utility requirements, typical per bbl fresh feed

Steam, lb 24Fuel (liberated), 103 Btu (80–120)Power, kWh 0.6Water, cooling, gal 300–400

Installation: Foster Wheeler has designed and constructed crudeunits having a total crude capacity in excess of 10 MMbpsd.

Reference: Encyclopedia of Chemical Processing and Design,Mar-cel-Dekker, 1997, pp. 230–249.

Licensor: Foster Wheeler USA Corp.

Flash gas

Light naphtha

Heavy naphthaKerosine

Diesel

Cracker feed

To vac. system

Lt. vac. gas oil

Hvy. vac.gas oil

Vac. gas oil

(cracker feed)Asphalt

Stm.Stm.

34 5

6

7

8

9

10

11

2

1

Stm.

Crude

START

12




30/95

Crude distillation Application: The Shell Bulk CDU is a highly integrated concept. It sep-arates the crude in long residue, waxy distillate, middle distillatesand a naphtha minus fraction. Compared with stand-alone units, theoverall integration of a crude distillation unit (CDU), hydrodesulfur-

ization unit (HDS), high vacuum unit (HVU) and a visbreaker (VBU)results in a 50% reduction in equipment count and significantly reducedoperating costs. A prominent feature embedded in this design is the Shelldeepflash HVU technology. This technology can also be provided in cost-effective process designs for both feedprep and lube oil HVU’s as stand-alone units. For each application, tailor-made designs can be produced.

Description: The basic concept of the bulk CDU is the separationof the naphtha minus and the long residue from the middle distil-

late fraction which is routed to the HDS. After desulfurization in theHDS unit, final product separation of the bulk middle distillatestream from the CDU takes place in the HDS fractionator (HDF),which consists of a main atmospheric fractionator with side strippers.

The long residue is routed hot to a feedprep HVU, which recov-ers the waxy distillate fraction from long residue as the feedstock fora cat cracker or hydrocracker unit (HCU). Typical flashzone condi-tions are 415°C and 24 mbara. The Shell design features a deen-trainment section, spray sections to obtain a lower flashzone pres-sure, and a VGO recovery section to recover up to 10 wt% of asautomotive diesel. The Shell furnace design prevents excessivecracking and enables a 5-year run length between decoke.

Yields: Typical for Arabian light crude

Products % wt

Gas C1-C4 0.7Gasoline C5-150°C 15.2Kerosine 150-250°C 17.4Gasoil (GO) 250-350°C 18.3

VGO 350-370°C 3.6Waxy distillate (WD) 370-575°C 28.8Residue 575°C + 16.0

Economics: Due to the incorporation of Shell high capacity inter-nals and the deeply integrated designs, typical bulk crude distillersare 30% cheaper than alternative designs. Investment costs are

dependent on the required configuration and process objectives.Installation: Over 100 Shell CDU’s have been designed and oper-ated since the beginning of the century. Additionally, a total of some50 HVU units have been built while a similar number has been debot-tlenecked, including many third-party designs of feedprep and lubeoil HVU’s.

Licensor: Shell Global Solutions International B.V.

HCU

VBU

Flash columnVBU

HDS

Storage

Kero

LGO

Rec NHT

FG

LPG

Tops

Naphtha

KeroGO

Bleed

Residue

HGO

WD

VGO

LR

Crude

Vac

CDU

HDF

HVU




31/95

Deasphalting Application: Prepare quality feed and blending stock using theLow-Energy Deasphalting (LEDA) Process.

Products: Bright stocks for lube oil refining, catalytic cracking and hydrocracking feed; specification asphalt.

Description: Residue is extracted with liquid hydrocarbon solventin a rotating disc contactor (1) where extraction efficiency is main-tained at all charge rates by varying rotor speed. Deasphalted oil sep-arator recovers solvent at supercritical conditions (2) and asphalt flash(3) recovers solvent. Products are steam stripped (4, 5).

Operating conditions: Typical ranges are: solvent, various blends

of C2–C7 hydrocarbons including light naphthas. Pressure, 300 to 600psig. Temp., 120°F to 450°F. Solvent/oil ratio, 4/1 to 13/1.

Yields:

Feed, type Lube oil Cracking stockGravity, °API 6.6 6.5Sulfur, wt% 4.9 3.0Rams carbon, wt% 20.1 21.8

Visc., SSU @ 210°F 7,300 8,720Ni/V, ppm 29/100 46/125DAO Case 1 Case 2Yield, vol% on feed 30 53 65Gravity, °API 20.3 17.6 15.1Sulfur, wt% 2.7 1.9 2.2Rams carbon, wt% 1.4 3.5 6.2

Visc., SSU @ 210°F 165 307 540Ni/V, ppm 0.25/0.37 1.8/3.4 4.5/10.3 AsphaltSoftening pt, R&B, °F 149 226 240Penetration @ 77°F 12 0 0

Economics:Investment (basis: 40,000–2,000 bpsd, 4th Q, 1999, U.S. Gulf),$ per bpsd 800–3,000Utilities, typical per bbl feed: Lube oil CrackedFuel, 103 Btu 81 56Electricity, kWh 1.5 1.8

Steam, 150 psig, lb 116 11Water, cooling (25°F rise), gal 15 nil

Installation: 42 units.

Reference: Handbook of Petroleum Refining Processes, 2nd Ed.,McGraw-Hill, 1997, pp. 10.15–10.44.

Licensor: Foster Wheeler USA Corp.

START

Feed

1

2 4

35

Stm.

Stm.Stm.

Stm.

Asphalt

Sour water

Asphaltflashdrum

Asphalt heater

Extractiontower

Solventdrum

Deasphalted oil separator Deasphalted oil stripperDeasphalted oil




32/95

Deasphalting Application: Extract lubricating oil blend stocks and FCCU or hydro-cracker feedstocks with low metal and Conradson carbon contents fromatmospheric and vacuum resid using ROSE Supercritical Fluid Tech-nology. Can be used to upgrade existing solvent deasphalters. ROSE

may also be used to economically upgrade heavy crude oil.Products: Lube blend stocks, FCCU feed, hydrocracker feed, resinsand asphaltenes.

Description: Resid is charged through a mixer (M-1), where it is mixedwith solvent before entering the asphaltene separator (V-1). Counter-current solvent flow extracts lighter components from the resid whilerejecting asphaltenes with a small amount of solvent. Asphaltenes arethen heated and stripped of solvent (T-1). Remaining solvent solution goesoverhead (V-1) through heat exchange (E-1) and a second separation (V-

2), yielding an intermediate product (resins) that is stripped of solvent(T-2). The overhead is heated (E-4, E-6) so the solvent exists as a super-critical fluid in which the oil is virtually insoluble. Recovered solvent leavesthe separator top (V-3) to be cooled by heat exchange (E-4, E-1) and a cooler

(E-2). Deasphalted oil from the oil separator (V-3) is stripped (T-3) of dis-solved solvent. The only solvent vaporized is a small amount dissolvedin fractions withdrawn in the separators. This solvent is recovered in theproduct strippers. V-1, V-2 and V-3 are equipped with high-performanceROSEMAX internals. These high-efficiency, high-capacity internalsoffer superior product yield and quality while minimizing vessel size andcapital investment. They can also debottleneck and improve operationsof existing solvent deasphalting units.

The system can be simplified by removing equipment in the outlinedbox to make two products. The intermediate fraction can be shifted,into the final oil fraction by adjusting operating conditions. Only one

exchanger (E-6) provides heat to warm the resid charge and the smallamount of extraction solvent recovered in the product strippers.

Yields: The extraction solvent composition and operating condi-tions are adjusted to provide the product quality and yields requiredfor downstream processing or to meet finished product specifications.Solvents range from propane through hexane and include blends nor-mally produced in refineries.

Economics:Investment (basis: 30,000 bpsd, 4th Q 1998 U.S. Gulf Coast),$ per bpsd 1,250

Utilities, typical per bbl feed:Fuel absorbed, 103 Btu 80–110Electricity, kWh 2.0Steam, 150-psig, lb 12

Installation: Nineteen units in operation; combined capacity of 320,000 bpsd. Additional units are licensed.

Reference: Northup, A. H., and H. D. Sloan, “Advances in solventdeasphalting technology,” 1996 NPRA Annual Meeting, San Antonio.

Licensor: Kellogg Brown & Root, Inc.

Oils

Resins

Hot

oil

Hotoil

Asphaltenes

V - 1

T - 1

V -

2

T -

2

V -

3

T -

3

E-6

E-4E-1

E-2

P-1

P-2

M-1

Resid-uum

E-3

S-1START




33/95


34/95

Deep catalytic cracking Application: Selective conversion of gas oil and paraffinic residualfeedstocks.

Products: C2–C5 olefins, aromatic rich, high octane gasoline anddistillate.

Description: DCC is a fluidized process for selectively cracking a widevariety of feedstocks to light olefins. Propylene yields over 24 wt% areachievable with paraffinic feeds. A traditional reactor/regeneratorunit design uses a catalyst with physical properties similar to tradi-tional FCC catalyst. The DCC unit may be operated in two operationalmodes: maximum propylene (Type I) or maximum iso-olefins (Type II).Each operational mode utilizes unique catalyst as well as reaction con-ditions. Maximum propylene DCC uses both riser and bed cracking atsevere reactor conditions while Type II DDC uses only riser cracking like a modern FCC unit at milder conditions.

The overall flow scheme of DCC is very similar to that of a con-ventional FCC. However, innovations in the areas of catalyst devel-opment, process variable selection and severity and gas plant designenables the DCC to produce significantly more olefins than FCC in

a maximum olefins mode of operation.

This technology is quite suitable for revamps as well as grassroot applications. Integrating DCC technology into existing refiner-ies as either a grassroots or revamp application can offer an attrac-tive opportunity to produce large quantities of light olefins. In a mar-ket requiring both proplylene and ethylene, use of both thermaland catalytic processes is essential, due to the fundamental differ-ences in the reaction mechanisms involved. The combination of ther-mal and catalytic cracking mechanisms is the only way to increasetotal olefins from heavier feeds while meeting the need for a increasedpropylene to ethylene ratio. The integrated DCC/steam cracking complex offers significant capital savings over a conventional stand-alone refinery for propylene production.

Products: DCC Type I DCC Type II FCC

wt% FF

Ethylene 6.1 2.3 0.9

Propylene 20.5 14.3 6.8

Butylene 14.3 14.6 11.0

in which IC4= 5.4 6.1 3.3

Amylene — 9.8 8.5

in which IC5

= — 6.5 4.3

Installation: There are currently five operating units in China andone in Thailand. Several more units are under design in China.

Reference: Chapin, Letzsch and Zaiting, “Petrochemical options fromdeep catalytic cracking and the FCCU,” paper AM-98-44, NPRA Annual Meeting , March 1998.

Licensor: Stone & Webster Inc., a Shaw Group Co., Research Insti-tute of Petroleum

Regen. cat. standpipe

Combustion air

Regenerator

Flue gas

Product vaporsReactor

Vapor and catalystdistributor

Stripper

Reactor riser

Riser steam

Feed nozzles (FIT)




35/95

Deep thermal conversion Application: The Shell Deep Thermal Conversion process closes thegap between visbreaking and coking. The process yields a maximumof distillates by applying deep thermal conversion of the vacuumresidue feed and by vacuum flashing the cracked residue. High-dis-

tillate yields are obtained, while still producing a stable liquid resid-ual product, referred to as liquid coke. The liquid coke, not suitable forblending to commercial fuel, is used for speciality products, gasifica-tion and/or combustion, e.g., to generate power and/or hydrogen.

Description: The preheated short residue is charged to the heater(1) and from there to the soaker (2), where the deep conversiontakes place. The conversion is maximised by controlling the operat-ing temperature and pressure. The cracked feed is then charged to

an atmospheric fractionator (3) to produce the desired products likegas, LPG, naphtha, kerosine and gas oil. The fractionator bottomsare subsequently routed to a vacuum flasher (4), which recovers addi-tional gas oil and waxy distillate. The residual liquid coke is routed

for further processing depending on the outlet.

Yields: Depend on feed type and product specifications.

Feed, vacuum residue Middle East Viscosity, cSt @ 100°C 770

Products in % wt. on feedGas 4.0Gasoline ECP 165°C 8.0Gas oil ECP 350°C 18.1Waxy distillate ECP 520°C 22.5Residue ECP 520°C + 47.4

Economics: The investment ranges from 1,300 to 1,600 U.S.$/bblinstalled excl. treating facilities and depending on the capacity andconfiguration (basis: 1998)

Utilities, typical per bbl @ 180°CFuel, Mcal 26Electricity, kWh 0.5Net steam production, kg 20Water, cooling, m3 0.15

Installation: To date, four Deep Thermal Conversion units have been

licensed. In two cases this involved a revamp of an existing ShellSoaker Visbreaker unit. In addition, two units are planned forrevamp, while one grass-roots unit is currently under construction.Post start-up services and technical services on existing units areavailable from Shell.

Reference: Visbreaking Technology, Erdöl and Kohle, January 1986.


Charge

Stm. Stm.

Gas

Naphtha

Gas oil

Waxy distillate

Liquid coke

3

4

2

1




36/95

Delayed coking Application: Upgrading of petroleum residues (vacuum residue, bitu-men, solvent-deasphalter pitch and fuel oil) to more valuable liquidproducts (LPG, naphtha, distillate and gas oil). Fuel gas andpetroleum coke are also produced.

Description: The delayed coking process is a thermal process andconsists of fired heater(s), coke drums and main fractionator. Thecracking and coking reactions are initiated in the f ired heater undercontrolled time-temperature-pressure conditions. The reactions con-tinue as the process stream moves to the coke drums. Being highlyendothermic, the coking-reaction rate drops dramatically as coke-

drum temperature decreases. Coke is deposited in the coke drums.The vapor is routed to the fractionator, where it is condensed and frac-tionated into product streams—typically fuel gas, LPG, naphtha, dis-tillate and gas oil.

When one of the pair of coke drums is full of coke, the heater out-let stream is directed to the other coke drum. The full drum is takenoffline, cooled with steam and water and opened. The coke is removedby hydraulic cutting. The empty drum is then closed, warmed-upand made ready to receive feed while the other drum becomes full.

Benefits of Conoco-Bechtel’s delayed coking technology are:• Maximum liquid-product yields and minimum coke yield

through low-pressure operation, patented distillate recycle technol-ogy and zero (patented) or minimum natural recycle operation

• Maximum flexibility; distillate recycle operation can be usedto adjust the liquid-product slate or can be withdrawn to maximize

unit capacity• Extended furnace runlengths between decokings• Ultra-low-cycle-time operation maximizes capacity and asset

utilization• Higher reliability and maintainability enables higher onstream

time and lowers maintenance costs• Lower investment cost.

Economics: For a delayed coker processing 35,000 bpsd of heavy,high-sulfur vacuum residue, the U.S. Gulf Coast investment cost isapproximately U.S.$145–160 million.

Installation: Low investment cost and attractive yield structure hasmade delayed coking the technology of choice for bottom-of-the-bar-rel upgrading. Numerous delayed coking units are operating inpetroleum refineries worldwide.

Licensor: Bechtel Corp., and Conoco Inc.

Green coke

Cokedrums

Furnace

Fractionator

Feed

Gas oil

Distillate

Gas and naphthato gas plant




37/95

Desulfurization Application: GT-DeSulf addresses overall plant profitability bydesulfurizing the FCC stream with no octane loss and decreasedhydrogen consumption by using a proprietary solvent in an extrac-tive distillation system. This process also recovers valuable aro-

matics compounds.Description: FCC gasoline, with endpoint up to 210°C, is fed to theGT-DeSulf unit, which extracts sulfur and aromatics from the hydro-carbon stream. The sulfur and aromatic components are processedin a conventional hydrotreater to convert the sulfur into H2S. Becausethe portion of gasoline being hydrotreated is reduced in volume andfree of olefins, hydrogen consumption and operating costs are greatlyreduced. In contrast, conventional desulfurization schemes processthe majority of the gasoline through hydrotreating and caustic-

washing units to eliminate the sulfur. That method inevitably resultsin olefin saturation, octane downgrade and yield loss.

GT-DeSulf has these advantages:• Eliminates FCC-gasoline sulfur species to meet a pool gaso-

line target of 20 ppm• Preserves more than 90% of the olefins from being hydrotreated

in the HDS unit; and thus, prevents significant octane loss andreduces hydrogen consumption

• Fewer components (only those boiling higher than 210°C and thearomatic concentrate from ED unit) are sent to the HDS unit; conse-quently, a smaller HDS unit is needed and there is less yield loss

• No mercaptan extraction unit is required to treat non-thio-phene type of sulfurs

• Purified benzene and other aromatics can be produced fromthe aromatic-rich extract stream after hydrotreating

• Olefin-rich raffinate stream (from the ED unit) can be recy-cled to the FCC unit to increase the light olefin production.FCC gasoline is fed to the extractive distillation column (EDC). In

a vapor-liquid operation, the solvent extracts the sulfur compoundsinto the bottoms of the column along with the aromatic components,while rejecting the olefins and nonaromatics into the overhead asraffinate. Nearly all of the nonaromatics, including olefins, are effec-tively separated into the raffinate stream. The raffinate stream canbe optionally caustic washed before routing to the gasoline pool, or toa C3

= producing unit.Rich solvent, containing aromatics and sulfur compounds, is

routed to the solvent recovery column, (SRC), where the hydrocarbonsand sulfur species are separated, and lean solvent is recovered incolumns bottoms. The SRC overhead is hydrotreated by conventionalmeans and used as desulfurized gasoline, or processed through anaromatics recovery unit. Lean solvent from the SRC bottoms aretreated and recycled back to the EDC.

Economics: Production cost of $0.50/bbl of feed for desulfurizationand dearomatization.

Licensor: GTC Technology Corp.

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Lean solvent

Desulfurizedaromatic

extract

Steam

Desufurized/

de-aromatisedolefin-rich gasoline

Hydrogenation

Solventrecovery

column

Extractivedistillationcolumn

1

2

FCCgasolinefeed




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Dewaxing Application: To remove waxy components from lubrication base oilsstreams to simultaneously meet desired low-temperature propertiesfor dewaxed oils and produce hard wax as a salable byproduct.

Description: Waxy feedstock (raffinate, distillate or deasphalted oil)is mixed with a binary solvent system and chilled down in a very closely

controlled manner in scraped surface exchangers (1) and refriger-ated chillers (2) to form a wax/oil /solvent slurry. The dewaxed oil prod-uct is filtered through the primary filter stage (3) and routed to thedewaxed oil recovery section (6) for separation of solvent from oil. Waxy

stream from the primary stage is filtered again in the repulp filter (4)to reduce the oil content to approximately 10%. The low-oil content slackwax is then warmed to melt the low-melting-points waxes (soft wax)and is filtered in a third stage (5) to separate the hard wax from thesoft wax. The hard and soft wax products are each routed to solventrecovery sections (7, 8) to strip solvent out of the product streams(dewaxed oil, hard wax, and soft wax). The recovered solvent is collected,dried and recycled back to the chilling section.

Economics:

Investment (basis: 7,000 bpsd feedrate

capacity, 2000 U.S. Gulf Coast), $ per bpsd 10,500

Utilities, typical per bbl feed:

Fuel, 103 Btu 280Electricity, kWh 46Steam, lb 60Water, cooling (25°F rise), gal 1,500Solvent makeup, lb 0.6

Installation: Six in service. One new unit is scheduled for startupin early 2001.

Licensor: Bechtel Corp.

Refrigerant

Refrigerant

Hard wax

Water

Dewaxed oil

Steam

Soft wax

Waxy

feed Steam or water

RefrigerantProcess steam

Solventrecovery

3

2

1 6

7 8

54




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Electrical desalting Application: For removal of undesirable impurities such as salt,water, suspended solids and metallic contaminants from unrefinedcrude oil, residuums and FCC feedstocks.

Description: Salts such as sodium, calcium and magnesium chlo-

rides are generally contained in the residual water suspended in theoil phase of hydrocarbon feedstocks. All feedstocks also contain, asmechanical suspensions, such impurities as silt, iron oxides, sand andcrystalline salt. These undesirable components can be removed fromhydrocarbon feedstocks by dissolving them in washwater or causing them to be water-wetted. Emulsion formation is the best way to pro-

duce highly intimate contact between the oil and washwater phases.The electrical desalting process consists of adding process (wash)

water to the feedstock, generating an emulsion to assure maximumcontact and then utilizing a highly efficient AC electrical field to

resolve the emulsion. The impurity-laden water phase can then beeasily withdrawn as underf low.

Depending on the characteristics of the hydrocarbon feedstockbeing processed, optimum desalting temperatures will be in therange of 150°F to 300°F. For unrefined crude feedstocks, the desalteris located in the crude unit preheat train such that the desired tem-perature is achieved by heat exchange with the crude unit productsor pumparound reflux. Washwater, usually 3 to 6 vol%, is addedupstream and/or downstream of the heat exchanger(s). The combinedstreams pass through a mixing device thereby creating a stablewater-in-oil emulsion. Properties of the emulsion are controlled by

adjusting the pressure drop across the mixing device.The emulsion enters the desalter vessel where it is subjected to ahigh voltage electrostatic field. The electrostatic field causes the dis-persed water droplets to coalesce, agglomerate and settle to thelower portion of the vessel. The water phase, containing the variousimpurities removed from the hydrocarbon feedstock, is continuouslydischarged to the effluent system. A portion of the water stream maybe recycled back to the desalter to assist in water conservationefforts. Clean, desalted hydrocarbon product flows from the top of thedesalter vessel to subsequent processing facilities.

Desalting and dehydration efficiency of the oil phase is enhancedby using EDGE (Enhanced Deep-Grid Electrode) technology whichcreates both high and low intensity AC electrical fields inside the ves-sel. Demulsifying chemicals may be used in small quantities toassist in oil/water separation and to assure low oil contents in theeffluent water.

Licensor: Howe-Baker Engineers, Inc.

Hydrocarbonfeedstock

Demulsifierchemical

Process water

AlternateMixingdevice

Effluent water

Electricalpower unit

Desalted product

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Internalelectrodes LC




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Ethers Application: To produce high-octane, low-vapor-pressure oxygenatessuch as methyl tertiary butyl ether (MTBE), tertiary amyl methylether (TAME) or heavier tertiary ethers for gasoline blending toreduce olefin content and/or meet oxygen/octane/vapor pressure

specifications. The processes use boiling-point/tubular reactor andcatalytic distillation (CD) technologies to react methanol (MeOH) orethanol with tertiary iso-olefins to produce respective ethers.

Description: For an MTBE unit, the process can be described as fol-lows. Process description is similar for production of heavier ethers.The C4s and methanol are fed to the boiling-point reactor (1)—a fixed-bed, downflow adiabatic reactor. In the reactor, the liquid is heatedto its boiling point by the heat of reaction, and limited vaporizationoccurs. System pressure is controlled to set the boiling point of thereactor contents and hence, the maximum temperatures. An isother-

mal tubular reactor is used, when optimum, to allow maximumtemperature control. The equilibrium-converted reactor effluentflows to the CD column (2) where the reaction continues. Concurrently,MTBE is separated from unreacted C4s as the bottom product.

This scheme can provide overall isobutylene conversions up to99.99%. Heat input to the column is reduced due to the heat pro-duced in the boiling-point reactor and reaction zone. Over time, theboiling-reactor catalyst loses activity. As the boiling-point reactorconversion decreases, the CD reaction column recovers lost conver-sion, so that high overall conversion is sustained. CD column overheadis washed in an extraction column (3) with a countercurrent waterstream to extract methanol. The water extract stream is sent to amethanol recovery column (4) to recycle both methanol and water.

C4s ex-FCCU require a well-designed feed waterwash to removecatalyst poisons for economic catalyst life and MTBE production.

Conversion: The information below is for 98% isobutylene conversion, typ-ical for refinery feedstocks. Conversion is slightly less for ETBE than forMTBE. For TAME and TAEE, isoamylene conversions of 95%+ are achiev-able. For heavier ethers, conversion to equilibrium limits are achieved.

Economics: Based on a 1,500-bpsd MTBE unit, (6,460-bpsd C4s ex-FCCU, 19% vol. isobutylene, 520-bpsd MeOH feeds) located on theU.S. Gulf Coast, the inside battery limits investment is:

Investment, $ per bpsd of MTBE product 3,500Typical utility requirements, per bbl of product

Electricity, kWh 0.5Steam, 150-psig, lb 210

Steam, 50-psig, lb 35Water, cooling (30° F rise), gal 1,050

Installation: Over 60 units are in operation using catalytic distil-lation to produce MTBE, TAME and ETBE. More than 100 ether proj-ects have been awarded to CDTECH since the first unit cameonstream in 1981. Snamprogetti has over 20 operating ether unitsusing tubular reactors.

Licensor: CDTECH (CDTECH and Snamprogetti are cooperating to further develop and license their ether technologies.)

raffinate

MTBE

Mixed C4s

Methanol C4

Water

4

Recycle methanol

2

1

3

START

START




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Fluid catalytic cracking Application: Conversion of gas oils and residues to high-valueproducts using the efficient and f lexible Orthoflow Catalytic Crack-ing process.

Products: Light olefins, high-octane gasoline and distillate.

Description: The converter is modularized to efficiently combine Kel-logg’s proven Orthoflow features with Mobil’s advanced design fea-tures. Regenerated catalyst flows through a lateral (1), fluidized by

gas, through the only expansion joint (2) to the base of the externalvertical riser reactor (3). Feed enters through the proprietary ATOMAX feed injection system. Reaction vapors pass through apatented right-angle turn (4) and a patented closed-cyclone system

(5). Spent catalyst flows through a two-stage stripper (6) to regen-eration (7) where advanced catalyst distribution and air distributionare used. Either partial or complete CO combustion may be used inthe regenerator, depending on the coke-forming tendency of thefeedstock. The system uses a patented external flue gas plenum(8), all-vertical solids flow and improved plug valves (9, 10). Anadvanced dense-phase catalyst cooler (11) is used to optimize prof-itability when heavier feeds are processed.

Economics:Investment (basis: 50,000 bpsd fresh feed including converter, frac-tionator, vapor recovery and amine treating but not power recov-

ery; battery limit, direct material and labor, 1994 U.S. Gulf Coast),$ per bpsd 1,950–2,150Utilities, typical per bbl fresh feedElectricity, kWh 0.7–1.0Steam, 600 psig (produced) lb 40–200Catalyst, makeup, lb 0.10–0.15Maintenance, % of plant replacement cost per yr 3

Installation: More than 120 resulting in a total of over two and ahalf million bpd fresh feed, with 18 designed in the past 10 years.

Reference: Oil and Gas Journal, Vol. 88, No. 13, March 26, 1990,pp. 56–62.

Licensor: Kellogg Brown & Root, Inc.

Vapor to fractionator

Flue gas

Feed

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54

3

21

9

10

11

7

6

8




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Fluid catalytic cracking Application: The Shell FCC process converts heavy petroleum dis-tillates and residues to high-value products. Profitability is increasedby a reliable and robust process, which has flexibility to process heavyfeeds and maximize product upgrading.

Products: Light olefins, LPG, high octane gasoline and distillate.

Description: Hydrocarbon is fed to a short contact-time-riser byShell’s high performance feed nozzle system, ensuring good mixing and rapid vaporisation. Proprietary riser internals lower pressuredrop and reduce back mixing. The riser termination design pro-

vides rapid catalyst/hydrocarbon separation to maximise desiredproduct yields and a staged stripper achieves low hydrogen in cokewithout excessive gas or coke formation. A single stage partial burnregenerator delivers excellent performance at low cost (full burn can

also be applied). Cat coolers can be added for feedstock flexibil-ity.Flue gas cleanup is by Shell’s third stage separator and powerrecovery can be incorporated if justified.

There are currently two FCC design configurations. The Shell 2 Vessel design is recommended for feeds (including residue) withmild coking tendencies, the incorporation of reactor and regenera-tor elements within the vessels leads to low capital expenditure. TheShell External Reactor design is the preferred option for heavy feedswith high coking tendencies, delivering improved robustness.The pre-stripping cyclone reduces post riser coke make and the externalreactor design eliminates stagnant areas for coke growth. Cost effec-

tiveness is achieved through a simple, low-elevation design. Thedesigns have proven to be reliable due to incorporation of Shell’s exten-sive operating experience.

Shell can also provide advanced distillation designs, advanced processcontrol and optimisers as part of an integrated FCC design solution.

Installation: Shell has designed and licensed over 30 grassroots units,including seven for residue feed. Shell has revamped over 25 units,including the designs of other licensors. Shell has converted eightexisting distillate units to residue operation. A Shell close-coupledriser termination system has been designed for 14 units and Shell’shigh performance feed nozzles for nine units. Shell has over 1,000+

years of own FCC operational experience.

Reference: “Update on Shell Residue FCC Process and Opera-tion,” AIChE 1998 Spring Meeting.“Design and Operation of Shell’sResidue Catalytic Crackers in East Asia,” ARTC 1998 Conference.


Closecoupledcyclones

Stagedstripping

Riserinternals

Coldwallconstruction

Countercurrentregen.

Advancedspent catinlet device

Integral TSS

Countercurrent

regen

Coldwallconstruction

High preformance

nozzles

High

preformancenozzles

Hydrocarbon Processing Refining Processes 2000[2]

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Transcript of Hydrocarbon Processing Refining Processes 2000[2]