cd-refining 2000_1.pdf

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Hydrocarbon Processing ®

Refining Processes 2000

Alkylation Alkylation feed preparation Aromatics extraction Aromatics extracted distillation Aromatics recovery Benzene reduction Benzene saturation Catalytic cracking Catalytic dewaxing Catalytic reforming Coking Crude distillation Deasphalting Deep catalytic cracking Deep thermal conversion Delayed coking Desulfurization Dewaxing Electric desalting Ethers Fluid catalytic cracking Gas oil hydrotreatment Gas treating—H2S removal

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Gasification Gasoline desulfurization Gasoline desulfurization, ultra-deepHydrocracking Hydrocracking, residue Hydrocracking/hydrotreating—VGO Hydrodearomatization Hydrodesulfurization Hydrodesulfurization—UDHDS Hydrogenation Hydrotreating Hydrotreating—catalytic dewaxing Hydrotreating—HDAr Hydrotreating—HDHDC Hydrotreating, residue Iso-octane Isomerization Lube hydroprocessing Lube treating NOx abatement Oily waste treatment Olefins recovery Resid catalytic cracking Residue hydroprocessing




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Thermal gas oil process Treating Visbreaking




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process index contributor indexcontributor index key wordkey word



ABB Lummus Global Inc. CokingFluid catalytic crackingHydrocrackingHydrocrackingHydrotreatingIsomerizationThermal gasoil processVisbreaking

Akzo Nobel Chemicals B.V. Hydrodesulfurization—UDHDSHydrotreating—catalytic dewaxingIsomerization

BARCOCatalytic cracking

Bechtel Corp. Delayed cokingDewaxingLube treating

BP Corp. Hydrocracking

CDTECH EthersHydrogenationHydrotreatingIso-octane/iso-octeneIsomerization


contributingcompany/licensor


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Chevron Research and Technology Co. HydrocrackingHydrotreating

Conoco Inc. Desulfurization

ELF Crude distillation

ExxonMobil Research & Engineering Co. AlkylationCatalytic dewaxingGas treating—H2S removalHydrotreating—catalytic dewaxingLube treatingNOx abatementOily waste treatment

Foster Wheeler USA Corp. CokingCrude distillationDeasphaltingVisbreaking

Fuels Technology Division of Phillips Petroleum Co.AlkylationGasoline desulfurizationIsomerization

GTC Technology Corp. Aromatics recoveryDesulfurization




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Haldor Topsøe A/S HydrodearomatizationHydrotreating

Howe-Baker Engineers, Inc.Catalytic reformingElectrical desaltingHydrotreating

IFP Benzene reductionCatalytic reformingFluid catalytic crackingGas oil hydrotreatmentGasoline desulfurization, ultra-deepHydrocrackingHydrocracking/hydrotreating—VGOHydrotreating, residueIsomerizationResid catalytic cracking

IFP North America Gasoline desulfurization, ultra-deepHydrocracking/hydrotreating—VGO

Imperial Petroleum Recovery Corp.Oily waste treatment

Kellogg Brown & Root, Inc.DeasphaltingFluid catalytic crackingHydrocracking




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Kellogg Brown & Root, Inc. continuedHydrodesulfurization—UDHDSHydrotreating—HDHDCIso-octaneIsomerization

Krupp Uhde Aromatics extractive distillation

Lyondell Chemical Co. Isomerization

Merichem Co.Treating

Neste Engineering Oy Iso-octane

Oxy Research & Development Co.Hydrocracking

Pro-Quip Corp.Olefins recovery

Research Institute of PetroleumDeep catalytic cracking

Shell Global Solutions International B.V.Crude distillationDeep thermal conversionFluid catalytic crackingGasificationHydrocrackingHydrotreating




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Shell Global Solutions International B.V. continuedLube hydroprocessingResidue hydroprocessingVisbreaking

Shell International Oil Products B.V.Thermal gasoil process

SK Corp. Lube treating

Snamprogetti SpA EthersIso-octane/iso-octene

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

Stratco Inc. Alkylation

TECHNIP Crude distillation

UOP LLC AlkylationAlkylationCatalytic crackingCatalytic reformingCokingDeasphaltingFluid catalytic cracking




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UOP LLC continuedHydrocrackingHydrodesulfurizationHydrotreatingHydrotreatingIsomerizationVisbreaking

VEBA OEL Technologie und Automatisierung GmbH Hydrocracking

Washington Group International Lube treating




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AlkylationApplication: 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 feedAlkylate quality 96 RON/94 MON

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

1 45 6

32

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REFINING PROCESSES 2000

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

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

Products: An ultra-low-sulfur, high-octane and low-RVP blendingstock 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 ascan 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 productGravity, API 70.1 71.1RVP, psi 6–7 6–7ASTM 10%, °F 185 170ASTM 90%, °F 236 253RONC 96.0 93.5

Per bbl olefin convertedi-Butane consumed, bbl 1.139 1.175Alkylate 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



AlkylationApplication: 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 alongwith 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 pointswithin 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 to96 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 1.85Acid, 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



AlkylationApplication: 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



AlkylationApplication: 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 component The 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



Alkylation feed preparationApplication: 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 alkylationproduct: The table below shows the results of an Alkyfining unittreating an FCC C4-HF-alkylation unit feed containing 0.8% 1,3-butadiene.

Butadiene in alkylate, ppm <101-butene isomerization, % 70Butenes yield, % 100.5RON increase in alkylate 2MON increase in alkylate 1Alkylate end-point reduction, °C –20

The increases in MON, RON and butenes yield are reflected in asubstantial octane-barrel increase while the lower alkylate endpoint results in reductions in ASO production and HF consumption.

Economics:

Investment: Grassroots ISBL cost: For an HF unit, $/bpsd 430 For an H2SO4 unit, $/bpsd 210

Annual savings for a 10,000-bpsd alkylation unit:For an HF unit: U.S.$ 4.1 million For an H2SO4 unit: U.S.$ 5.5 million

Installation: Over 80 units, for a total capacity of 700,000 bpsd.

Licensor: IFP.

START

Hydrogen

Reactor Stripper

Fuel gas

HydroisomerizedC4s to alkylation

C4 feed



Aromatics extractionApplication: 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 0.46Water, cooling (T=10ºC), m3/t 12Electric power, kWh/t 18

Production yieldBenzene, % ~100Toluene, % 99.7EB, Xylenes,% 94.0

PurityBenzene, 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

Extractivedistillation

column

Water

Water

Feed BTX-fraction

Extractor

Washer

Water &solvent



Aromatics extractive distillationApplication: 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 satisfiesthe necessary solvent properties needed for this process includinghigh selectivity, thermal stability and a suitable boiling point.

Economics:Pygas feedstock:

Benzene Benzene/tolueneProduction yield

Benzene 99.95% 99.95%Toluene – 99.98%

QualityBenzene 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

QualityBenzene 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



Aromatics recoveryApplication: 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• Insignif icant 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 nonaromatichydrocarbons 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 asolvent-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-BTXextraction 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

Water

Raffinate

Solventrecovery

column

Extractivedistillationcolumn

1

2



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

Description: Full-range reformate from either a semiregenerativeor 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 whenthe light reformate is destined to be isomerized, because iso-C7paraffins tend to be cracked to C3 and C4 components, thus leadingto 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

Heavyreformate

Lightreformate

C5/C6



Benzene saturationApplication: 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 feedstocksthat 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 froma 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 firstoffered 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

23

Product

Light end to FG

Feedeffluent

exchanger

Preheater(for startup only)

Makeup hydrogen

Feed



Catalytic crackingApplication: To selectively convert gas oils and residual feedstocksto higher-value cracked products such as light olefins, 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 fallingcurtain 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



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

Products: High VI / low-aromatics lube base oils (light neutralthrough 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 QuenchZone 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 2,500 LHSV 0.4 to 3.0Conversion depends on feed wax contentPour point reduction as needed.

Yields:Light neutral Heavy neutral

Lube 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.


Waxyfeed

Lube product

HDTRxr

HDWRxr

Purge

HPstripper

MP steam

Oilywater

LTsepHT

sep

Water

M/U

Rec

Fuel ags to LP absorber

Wild naphtha

Sour water

Sourwater

Distillate

Vacuum system

MakeupH2

MP steamVac

dryer

Vacstrip.

Waterwash

Waterwash



Catalytic reformingApplication: 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 (<10 ppm) may be reformedwithout hydrotreatment.

Operating conditions: 875°F to 1,000°F and 150 to 400 psig reac-tor conditions.

Yields: Depend on feed characteristics, product octane and reactorpressure. The following yields are one example. The feed contains51.4% paraffins, 41.5% naphthenes and 7.1% aromatics, and boilsfrom 208°F to 375°F (ASTM D86). Product octane is 99.7 RONC andaverage reactor pressure is 200 psig.

Component wt% vol%H2 2.3 1,150 scf/bblC1 1.1 —C2 1.8 —C3 3.2 —iC4 1.6 —nC4 2.3 —C5+ 87.1 —LPG — 3.7Reformate — 83.2

Economics:Utilities, (per bbl feed)Fuel, 103 Btu release 275Electricity, kWh 7.2Water, cooling (20°F rise), gal 216Steam produced (175 psig sat), lb 100

Licensor: Howe-Baker Engineers, Inc.

Reactors

Heaters

Net gas

High-pressure

flash

Low-pressure

flashCW

Liquid to stabilizer

SteamBFW

Hotfeed

START



Catalytic reformingApplication: 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 eachcycle. 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 itsspecific area for more than 600 cycles.

Finally, with the new CR401 (gasoline mode) and AR501 (aromat-ics production) catalysts specifically developed for ultra-low operatingpressure 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 lightArabian feedstock:

Conventional OctanizingOper. press., kg/cm2 10–15 <5Yield, wt% of feed

Hydrogen 2.8 3.8C5

+ 83 88RONC 100 102MONC 89 90.5

Economics:Investment (basis 25,000 bpsd continuous

Octanizing unit, battery limits, erected cost, mid-2000 Gulf Coast), U.S.$ per bpsd 1,700

Utilities: typical per bbl feed:Fuel, 103 kcal 65Electricity, kWh 0.96Steam, net, HP, kg 12.5Water, boiler feed, m3 0.03

Installation: Of 104 units licensed, 56 units are designed with con-tinuous regeneration technology capability.

Reference: “Continuing Innovation In Cat Reforming,” NPRAAnnual Meeting, March 15–17, 1998, San Antonio.

“Fixed Bed Reformer Revamp Solutions for Gasoline Pool Improve-ment,”Petroleum Technology Quarterly, Summer 2000.

Licensor: IFP.

Feed

2 34 5

1

Reformate

START



Catalytic reformingApplication: 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 200/360 200/360Operating conditionsReactor pressure, psig 200 50C5

+ octane, RONC 100 100Catalyst R-72 staged loading R-274Yield 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 refinersoperate 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



CokingApplication: 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 pitchGravity, °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



CokingApplication: Manufacture petroleum coke and upgrade residues tolighter hydrocarbon fractions using the Selective Yield Delayed Cok-ing (SYDEC) process.

Products: Coke, gas, LPG, naphtha and gas oils.

Description: Charge is fed directly to the fractionator (1) where itcombines with recycle and is pumped to the coker heater where it isheated to coking temperature, causing partial vaporization and mildcracking. The vapor-liquid mix enters a coke drum (2 or 3) for fur-ther cracking. Drum overhead enters the fractionator (1) to be sep-arated into gas, naphtha, and light and heavy gas oils. There are atleast two coking drums, one coking while the other is decoked usinghigh-pressure water jets.

Operating conditions: Typical ranges are:Heater outlet temperature, °F 900–950Coke drum pressure, psig 15–100Recycle ratio, equiv. fresh feed 0.05–1.0Increased coking temperature decreases coke production; increases

liquid yield and gas oil end point. Increasing pressure and/or recy-cle ratio increases gas and coke make, decreases liquid yield and gasoil end point.

Yields:Feed, source Venezuela N. Africa —Type Vac. resid Vac. resid Decant oilGravity, °API 2.6 15.2 40.7Sulfur, wt% 4.4 0.7 0.5Concarbon, wt% 23.3 16.7 —Operation Max dist. Anode coke Needle cokeProducts, wt%Gas 8.7 7.7 9.8Naphtha 10.0 19.9 8.4Gas oil 50.3 46.0 41.6Coke 31.0 26.4 40.2

Economics:Investment (basis: 65,000–10,000 bpsd, 4th Q, 1999, U.S. Gulf),$ per bpsd 2,500–4,000Utilities, typical per bbl feed:Fuel, 103 Btu 120Electricity, kWh 3.6Steam (exported), lb (40)Water, cooling, gal 36

Installation: More than 58,000 tpd of fuel, anode and needle coke.

Reference: Handbook of Petroleum Refining Processes, 2nd Ed., pp.12.25–12.82; Oil & Gas Journal, Feb. 4, 1991, pp. 41–44; HydrocarbonProcessing, Vol. 71, No. 1, January 1992, pp. 75–84.

Licensor: Foster Wheeler USA Corp./UOP LLC

1

Gas

Naphtha

Steam

Light gas oil

Heavy gas oilFeed

START

2 3



.

Crude distillationApplication: 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 futureregulations. 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 and vacuum distillation, gas plant and rectification tower) 750 to 950 $ 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 fuel

per 100 tons of Crudefor Arabian Heavy 1.15 tons of fuel

per 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.



Crude distillationApplication: 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 aheavy 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 of675°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 astwo sidestreams. The two sidestreams are combined to form crack-ing feedstock. An asphalt base stock is pumped from the bottom ofthe 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 85Vac. 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 feedSteam, 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 naphtha

Kerosine

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

89

10

11

2

1

Stm.Crude

START

12



Crude distillationApplication: 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 % wtGas C1-C4 0.7Gasoline C5-150°C 15.2Kerosine 150-250°C 17.4Gasoil (GO) 250-350°C 18.3VGO 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 aredependent 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.

HCUVBUFlash columnVBU

HDS

Storage

Kero

LGO

Rec NHT

FG

LPG

Tops

Naphtha

KeroGOBleed

Residue

HGO

WD

VGOLR

Crude

Vac

CDU

HDF

HVU



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

Products: Bright stocks for lube oil refining, catalytic crackingand 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 21.8Visc., 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 6.2Visc., SSU @ 210°F 165 307 540Ni/V, ppm 0.25/0.37 1.8/3.4 4.5/10.3AsphaltSoftening 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 1.8Steam, 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

3 5

Stm.

Stm.Stm.

Stm.

Asphalt

Sourwater

Asphaltflashdrum

Asphalt heater

Extractiontower

Solventdrum

Deasphalted oil separator Deasphalted oil stripperDeasphalted oil



DeasphaltingApplication: 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. ROSEmay 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 oneexchanger (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 1,250Utilities, typical per bbl feed:Fuel absorbed, 103 Btu 80–110Electricity, kWh 2.0Steam, 150-psig, lb 12

Installation: Nineteen units in operation; combined capacity of320,000 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

Hotoil

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



DeasphaltingApplication: Prepare quality feed for FCC units and hydrocrackersfrom vacuum residue and blending stocks for lube oil and asphaltmanufacturing.

Products: Deasphalted oil (DAO) for catalytic cracking and hydro-cracking feedstocks, resins for specification asphalts, and pitch forspecification asphalts and residue fuels.

Description: Feed and light paraffinic solvent are mixed thencharged to the extractor (1). The DAO and pitch phases, both con-taining solvents, exit the extractor. The DAO and solvent mixture isseparated under supercritical conditions (2). Both the pitch andDAO products are stripped of entrained solvent (3,4). A secondextraction stage is utilized if resins are to be produced.

Operating conditions: Typical ranges are: solvent, various blends

of C3–C7 hydrocarbons including light naphthas. Pressure: 300 to 600psig. Temp.: 120 to 450°F. Solvent-to-oil ratio: 4/1 to 13/1.

Yields:Feed, type Lube oil Cracking stockGravity, °API 6.6 6.5Sulfur, wt.% 4.9 3.0CCR, wt% 20.1 21.8Visc, SSU@ 210°F 7,300 8,720NI/V, wppm 29/100 46/125

DAOYield, vol.% of Feed 30 53 65Gravity, °API 20.3 17.6 15.1Sulfur, wt% 2.7 1.9 2.2CCR, wt% 1.4 3.5 6.2Visc., SSU@ 210°F 165 307 540Ni/V, wppm 0.25/0.37 1.8/3.4 4.5/10.3

PitchSoftening point, R&B,°F 149 226 240

Penetration@77°F 12 0 0

Economics:Investment (basis: 2,000–40,000 bpsd 4th Qtr 2000, U.S. Gulf), $/bpsd 800–3,000Utilities, typical per bbl feed: Lube oil Cracking stockFuel, 103 Btu 81 56Electricity, kWh 1.5 1.8Steam, 150-psig, lb 116 11Water, cooling (25°F rise), gal 15 nil

Installations: 50+. This also includes both UOP and Foster Wheelerunits originally licensed separately before the merging the tech-nologies in 1996.

Reference: Handbook of Petroleum Refining Processes, 2nd Ed.,McGraw Hill, 1997, pp.10.15–10.60.

Licensor: UOP LLC.

2

3

1

Vacuumresiduecharge

Pitch

Pitchstripper

DAOstripper

DAO

DAOseparator

Extractor

4



Deep catalytic crackingApplication: 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 crackinglike 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 ina 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 crackingcomplex offers significant capital savings over a conventional stand-alone refinery for propylene production.

Products: DCC Type I DCC Type II FCC

wt% FFEthylene 6.1 2.3 0.9Propylene 20.5 14.3 6.8Butylene 14.3 14.6 11.0

in which IC4= 5.4 6.1 3.3

Amylene — 9.8 8.5in 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, NPRAAnnual 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)



Deep thermal conversionApplication: 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 routedfor further processing depending on the outlet.

Yields: Depend on feed type and product specifications.

Feed, vacuum residue Middle EastViscosity, 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 beenlicensed. 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



Delayed cokingApplication: 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 fired 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 maximizeunit 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



DesulfurizationApplication: 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). Ina 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.

START

Lean solvent

Desulfurizedaromatic

extract

Steam

Desufurized/de-aromatised

olefin-rich gasoline

HydrogenationSolvent

recoverycolumn

Extractivedistillationcolumn

1

2

FCCgasolinefeed



DewaxingApplication: 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. Waxystream 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

Waxyfeed Steam or water

RefrigerantProcess steam

Solventrecovery

3

2

1 6

7 8

54



Electrical desaltingApplication: 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 causingthem 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 toresolve the emulsion. The impurity-laden water phase can then beeasily withdrawn as underflow.

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 byadjusting 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.


Hydrocarbonfeedstock

Demulsifierchemical

Process waterAlternate

Mixingdevice

Effluentwater

Electricalpower unit

Desalted product

START

Internalelectrodes LC



EthersApplication: 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 pressurespecifications. 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 210Steam, 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 cooperatingto further develop and license their ether technologies.)

raffinate

MTBE

Mixed C4s

Methanol C4

Water

4

Recycle methanol

2

1

3

START

START



Fluid catalytic crackingApplication: Selective conversion of a wide range of gas oils into high-value products. Typical feedstocks are virgin or hydrotreated gasoils but may also include lube oil extract, coker gas oil and resid.

Products: High-octane gasoline, light olefins and distillate. Flexi-bility of mode of operation allows for maximizing the most desirableproduct. The new Selective Component Cracking (SCC) technologymaximizes propylene production.

Description: The Lummus process incorporates an advanced reactionsystem, high-efficiency catalyst stripper and a mechanically robust, sin-gle-stage fast fluidized bed regenerator. Oil is injected into the base of theriser via proprietary Micro-Jet feed injection nozzles (1). Catalyst and oilvapor flow upwards through a short contact time, all-vertical riser (2)where the raw oil feedstock is cracked under optimum conditions. Reac-tion products exiting the riser are separated from the spent catalyst in

a patented, direct-coupled cyclone system (3). Product vapors are routeddirectly to fractionation, thereby eliminating nonselective, post-risercracking and maintaining the optimum product yield slate. Spent cata-lyst containing only minute quantities of hydrocarbon is discharged fromthe diplegs of the direct-coupled cyclones into the cyclone containment ves-sel (4). Trace hydrocarbons entrained with spent catalyst are removed inthe stripper (5) using stripping steam. The net stripper vapors are routedto the fractionator via specially designed vents in the direct-coupledcyclones. Catalyst from the stripper flows through the slide valve (6) tothe spent catalyst distributor (7) which disperses catalyst evenly acrossthe regenerator (8). Catalyst is regenerated by efficient contacting withair to affect complete combustion of coke. For resid-containing feeds, theoptional catalyst cooler is integrated with the regenerator. The resultingflue gas exits via cyclones (9) to energy recovery/flue gas treating. The hotregenerated catalyst is withdrawn via an external withdrawal well (10).The well allows independent optimization of catalyst density in theregenerated catalyst slide valve (11) pressure drop and ensures stable cat-alyst flow back to the riser feed injector zone.

Economics: Investment, (basis: 30,000 bpsd including reaction/regeneration sys-tem and product recovery. Excluding offsites, power recovery andflue gas scrubbing. U.S. Gulf Coast 1998)$ per bpsd (typical) 2,100–2,800Utilities, typical per bbl fresh feed:Electricity, kWh 0.8–1.0Steam, 600 psig (produced) 50–200Maintenance, % of investment per year 2–3

Installation: 13 installations to date and two currently in design aswell as numerous revamps. Twelve applications of the patenteddirect-coupled cyclones are in operation, construction or design.

References: Chan, T. Y., and K. M. Sundaram, “Advanced FCCUTechnology for Maximum Propylene Production.” AIChE SpringMeeting, 2nd International Conference in Refinery Processing, Hous-ton, March 14–18, 1999.

Licensor: ABB Lummus Global Inc.

Feed

Flue gas

6

10

1 11

7 8

9

23

4

5

Vapor to fractionator

START



Fluid catalytic crackingApplication: Conversion of gas oils and residues to high-valueproducts using the efficient and flexible 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 proprietaryATOMAX 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.


Vapor to fractionator

Flue gas

Feed

START

54

3

21

910

11

7

68



Fluid catalytic crackingApplication: 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 mixingand 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 canalso 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 2Vessel 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

IntegralTSS

Countercurrent

regen

Coldwallconstruction

High preformancenozzles

Highpreformancenozzles

Riserinternals

Stagedstripping

Pre-strippingreactorcyclone

To fractionatorTo fractionator Externalcyclones

Shell 2 vessel design Shell external reactor design



Fluid catalytic crackingApplication: Selective conversion of gas oil feedstocks.

Products: High-octane gasoline, distillate and C3–C4 olefins.

Description: Catalytic and selective cracking in a short-contact-timeriser (1) where oil feed is effectively dispersed and vaporized througha proprietary feed injection system. Operation is carried out at a tem-perature consistent with targeted yields. Reaction products exit theriser-reactor through a high-efficiency, proprietary riser terminationdevice (2). Spent catalyst that has not been cooled is pre-stripped and

flows through a rapid preliminary stripping section, followed by ahigh-efficiency baffled stripper prior to regeneration.

Vapor products only are quenched using Amoco’s proprietary tech-nology to give the lowest possible dry gas and maximum gasoline yield.The hydrocarbons are further cleaned by cyclones before they aretransferred to fractionation. Catalyst regeneration is carried out ina single regenerator (3) equipped with proprietary air rings andcatalyst distribution system, and may be operated for either full orpartial CO combustion. Maximum production of more desirableproducts can be achieved with the proprietary Mixed TemperatureControl (MTC) system (4). Heat removal for heavier feedstocks maybe accomplished by the use of a reliable dense-phase catalyst coolerwhich has been commercially proven in over 24 units and is licensedexclusively by Stone & Webster/IFP. As an alternative to catalyst cool-ing, this unit can easily be retrofitted to a two-regenerator systemin the event that a future resid operation is desired.

The converter vessels use a cold-wall design that results in min-imum capital investment and maximum mechanical reliability andsafety. Cracking operation makes use of advanced fluidization tech-nology combined with a proprietary reaction system. Unit design istailored to the refiner’s needs and can include wide turndown flex-ibility. Available options include power recovery in addition to waste-heat recovery.

Installation: Stone & Webster has licensed 26 full-technology unitsand performed more than 100 revamp projects.

Reference: Letzsch, W. S., “1999 FCC Technology Advances,” 1999Stone & Webster Eleventh Annual Refining Seminar at NPRA Q&A,Dallas, Oct. 5, 1999.

Licensor: Stone & Webster Inc., a Shaw Group Co./Institut Françaisdu Pétrole.

Regenerator

Reactor

Regen. cat.standpipe

Stripper

Reactor riser

Feed nozzles

Proprietary risertermination device



Fluid catalytic crackingApplication: Selectively convert gas oils and resid feedstocks intohigher-value products using the FCC/RFCC/PETROFCC process.

Products: Light olefins (for alkylation, polymerization, etherifica-tion or petrochemicals), LPG, high-octane gasoline, distillates andfuel oils.

Description: The combustor-style unit is used to process gas oils andmoderately contaminated resids, while the two-stage unit is used formore contaminated resids.

In either unit style, the reactor section is similar. A lift media of lighthydrocarbons, steam or a mixture of both contacts regenerated cata-lyst at the base of the riser (1). This patented acceleration zone (2), withelevated Optimix feed nozzles (3), enhances the yield structure by

effectively contacting catalyst with finely atomized oil droplets. The liftgas conditions the catalyst and passivates active metal sites.

The reactor zone features a short-contact-time riser and a state-of-the-art riser termination device (4) for quick separation of cata-lyst and vapor, with high hydrocarbon containment (VSS/VDS tech-nology). This design offers high gasoline yields and selectivity withlow dry gas yields. Steam is used in an annular stripper (5) to dis-place and remove entrained hydrocarbons from the catalyst. Exist-ing units can be revamped to include these features (1–5).

The combustor-style regenerator (6) burns coke, in a fast-fluidizedenvironment, completely to CO2 with very low levels of CO. The cir-culation of hot catalyst (7) from the upper section to the combustorprovides added control over the burn-zone temperature and kinet-ics and enhances radial mixing. Catalyst coolers (8) can be added tonew and existing units to reduce catalyst temperature and increaseunit flexibility for commercial operations of feeds up to 6 wt% Con-radson carbon.

For heavier resid feeds, the two-stage regenerator is used. In thefirst stage, upper zone (9), the bulk of the carbon is burned from thecatalyst, forming a mixture of CO and CO2. Catalyst is transferredto the second stage, lower zone (10), where the remaining coke isburned in complete combustion, producing low levels of carbon onregenerated catalyst. A catalyst cooler (11) is located between thestages. This configuration maximizes oxygen use, requires only onetrain of cyclones and one flue gas stream (12), avoids costly multi-ple flue gas systems and creates a hydraulically-simple and well-cir-culating layout. The two-stage regenerator system has processed feedsup to 10 wt% Conradson carbon.

PETROFCC is a customized application using mechanical fea-tures such as RxCAT technology for recontacting carbonized catalyst,high-severity processing conditions and selected catalyst and addi-tives to produe high yields of propylene, light olefins and aromaticsfor petrochemical applications.

Licensor: UOP LLC.

12

11

To fractionation To fractionation

Combustor-styleregenerator

Flue gasFlue gas

Combusterriser

Hot-catalystcirculation

Catalystcooler

Catalystcooler

1st stage

2nd

stage

Catalysttransfer line

Air SecondaryairLift media Lift media

Feed Feed

Primaryair

FCC

8

7

4 4

5 5

3 3

21

21

Two-stageregenerator

RFCC

6 10

9



Gas oil hydrotreatmentApplication: Produce high-quality diesel fuel via Prime-D technol-ogy for deep hydrodesulfurization, ultra-deep hydrodesulfurization,aromatics reduction and cetane improvement.

Description: In the basic process shown above, feed and hydrogenare heated in the feed-furnace effluent exchanger (1) and furnace (2),and enter the reactor (3), where sulfur content is reduced using a rel-atively inexpensive catalyst. The reactor effluent is cooled byexchanger (1) and air cooler (4), and separated in the tri-phase sep-arator (5). The hydrogen-rich gas phase is recycled to the amine unitfor H2S removal and recompression (7), and recycle to the feed-effluent exchanger. The liquid phase is sent to the stripper (8),where gas and naphtha are removed. The stripper bottoms flow tothe drier (9) and then to blending and storage.

Through provisions in the basic design, the refiner will be able to

meet (avoiding unjustified investment) future sulfur, specific grav-ity, cetane and heavy polyaromatics (HPA) specifications when theyarrive (ultimately <5 ppm sulfur and <1–2% PAH) via stepwiseadditions. These additions include items such as an additional reac-tor, different catalysts, changing operating conditions and usingtwo stages as shown in Cases 1–4 below. For ultra-low sulfur targetsproprietary design reactor internals and quench systems are installed.

Examples of various Prime-D processing options

Case 1: Case 2: Case 3: Case 4:Low sulfur Ultra-low sulfur. Improved Full aromaticsyear 2000 HDS with cetane hydrogenationHDS unit implemented single-stage two-state

ultra- HDS–HDA .HDS–HDAdeep HDSprovisions

Sulfur, ppm 350 < 10 < 10 < 5Specific

gravity < 0.845 < 0.840 < 0.834 < 0.825PAH content,

wt% 11 < 2–3 < 2 < 1–2Cetane

number 51 55 58 58Pressure P 1.7 x P 2.5 x P 1.7 x PLHSV, h-1 Base 0.4 x Base 0.25 x Base 0.4 x Base +

noble metalISBL

investment Base 1.65 x Base 2.1 x Base 2.7 x Base

Installation: Over 100 middle distillate hydrotreaters have beenlicensed or revamped. They include low-and ultra-low-sulfur (< 50ppm), as well as cetane improvement units.

Reference: “Distillate hydrotreating routes: from deep HDS to cetanenumber improvement,” IFP Refining Seminar, November 1999.

Licensor: IFP.

START H2 recycle

H2S

Amineunit

Low-sulfurproduct

Drier

895

4

32

1

67

Offgas

H2

Feed



Gas treating—H2S removalApplication: The FLEXSORB process selectively removes H2S in thepresence of CO2 in petroleum refining, natural gas processing, petro-chemicals operations and power generation. This technology uses aproprietary sterically hindered amine solvent in conventional gas-treating equipment.

Products: FLEXSORB produces a clean gas containing as little as10 vppm H2S and an enriched acid gas for treatment in a sulfur recov-ery process.

Description: The feed (acid gas) is countercurrently contacted withlean solvent where H2S is selectively absorbed. The rich solvent isthen regenerated in a reboiled regenerator.

Economics: FLEXSORB offers 10% to 40% circulation rate andenergy requirement savings relative to competing conventional tech-nology. Thus, smaller equipment can be used, and lower spacerequirements are needed. The process is particularly applicable inretrofit, revamp or expansion scenarios and/or situations wherespace is at a premium. It is not unusual to be able to use FLEXSORBfor a low cost 25% debottleneck of existing facilities. FLEXSORB canbe used for Claus sulfur plant tail-gas cleanup, for natural gas treat-ing/sweetening and for acid-gas enrichment.

Installation: More than 40 applications of FLEXSORB are in oper-ation, with several startups within the last year.

References: Chudlinski, G. R., et al., “Commercial Experiencewith FLEXSORB Absorbent,” AIChE National Meeting, New Orleans,April 8, 1986.

van Son, K. J., et al., “Asgard B process selection for hydrogensulfide removal and disposal,” Gas Processors Association 78thAnnual Convention, Nashville, March 1-3, 1999.


Absorber

Refluxdrum

Condenser

Regenerator

ReboilerSteam

H2S -free treated gas H2S -richacid gas to

sulfurrecovery

Sourfeed gas

START

Leansolution Rich

solution

Cooler

Heatexchanger



GasificationApplication: The Shell Gasification Process (SGP) converts the heav-iest residual liquid hydrocarbon streams with high-sulfur and metalscontent into a clean synthesis gas and valuable metal oxides. Sulfur (S)is removed by normal gas treating processes and sold as elemental S.

The process converts residual streams with virtually zero value as fuel-blending components into valuable, clean gas and byproducts. This gascan be used to generate power in gas turbines and for making H2 by thewell-known shift and PSA technology. It is one of the few ultimate, envi-ronmentally acceptable solutions for residual hydrocarbon streams.Products: Synthesis gas (CO+H2), sulfur and metal oxides.Process description: Liquid hydrocarbon feedstock (from very lightsuch as natural gas to very heavy such as vacuum flashed crackedresidue, VFCR and ashphalt ) is fed into a reactor, and gasified with

pure O2 and steam. The net reaction is exothermic and produces a gasprimarily containing CO and H2. Depending on the final syngas appli-cation, operating pressures, ranging from atmospheric up to 65 bar, caneasily be accommodated. SGP uses refractory-lined reactors that arefitted with both burners and a heat-recovery-steam generator, designedto produce high-pressure steam—over 100 bar (about 2.5 tons per tonfeedstock). Gases leaving the steam generator are at a temperatureapproaching the steam temperature; thus further heat recovery occurrsin an economizer.

Soot (unconverted carbon) and ash are removed from the raw gasby a two-stage waterwash. After the final scrubbing, the gas is vir-tually particulate-free; it is then routed to a selective-acid-gas-removal system. Net water from the scrubber section is routed to thesoot ash removal unit ( SARU ) to filter out soot and ash from theslurry. By controlled oxidation of the filtercake, the ash componentsare recovered as valuable oxides—principally vanadium pentoxide.The (clean) filtrate is returned to the scrubber.

A related process—the Shell Coal Gasification Process (SCGP)—gasifies solids such as coal or petroleum coke. The reactor is differ-ent, but main process layout and work-up are similar.Installation: Over the past 40 years, more than 150 SGP unitshave been installed, that convert residue feedstock into synthesis gasfor chemical applications. The latest, flagship installation is in theShell Pernis refinery near Rotterdam, The Netherlands. This highlycomplex refinery depends on the SGP process for its H2 supply. Sim-ilar projects are underway in India and Italy.

The Demkolec Power plant at Buggenum, The Netherlands produces250 Mwe based on the SCGP process. The Shell middle distillate syn-thesis plant in Bintulu, Malaysia, uses SGP to convert 100 million scfdof natural gas into synthesis gas used for petrochemical applications.Reference: “Shell Gasification Process,” AIChE Spring NationalMeeting, paper 70b, March 5–9, 2000. “Shell Pernis NetherlandsRefinery Residue Gasification Project,” 1999 Gasification Tech-nologies Conference, San Francisco, Oct. 17–20, 1999.Licensor: Shell Global Solutions International B.V.

Ni/VashFiltercake

work up

OxygenBleed to SWS

SyngasProcesssteam

Boiler

Steam

Oil

BFW

Scrubber

Effluentboiler

Sootquench

Filtration

Reactor



Gasoline desulfurizationApplication: Convert high-sulfur gasoline streams into a low-sul-fur gasoline blendstock using S Zorb sulfur-removal technology.

Products: A very-low sulfur blending stock for gasoline motor fuels.Applications for diesel are under development.

Description: Gasoline from the fluid catalytic cracker unit is com-bined with a small hydrogen stream and heated. Vaporized gasolineis injected into the expanded fluid-bed reactor (1), where the pro-prietary sorbent removes sulfur from the feed. A disengaging zonein the reactor removes suspended sorbent from the vapor, which exitsthe reactor to be cooled.

Regeneration: The sorbent (catalyst) is continuously withdrawn fromthe reactor and transferred to the regenerator section (2), where thesulfur is removed as SO2 and sent to a sulfur-recovery unit. Thecleansed sorbent is reconditioned and returned to the reactor. Therate of sorbent circulation is controlled to help maintain the desiredsulfur concentration in the product.

Economics:General operating conditions:

Temperature, °F 650–775 Pressure, psig 100–300 Space velocity, whsv 4–10 Hydrogen purity, % 70–99 Total H2 usage, scf/bbl 40–60

Case study premises:25,000-bpd feed775-ppm feed sulfur25-ppm product sulfur (97% removal)No cat gasoline splitter

Results:C5+ yield, vol% of feed ~ 100 Lights yield, wt% of feed < 0.2(R+M) Loss2 0.6 (or <0.6)

Capital cost, $/bbl 900Operating cost, ¢/gal* 0.9

* Includes utilities, 4% per year maintenance and sorbent costs.

Installation: First commercial operations in early 2001 at a Texasfacility. Field license sold to a major U.S. refiner.


Hydrogen Chargeheater

Productseparator

Regen.

Stabil

izer

1 2

Cat.gasoline

Fuel gas

Desulfurizedproduct

To SRU

Air

Nitrogen

Sorber

Recyclecompressor

Steam

SO2 & CO2



Gasoline desulfurization,ultra-deep Application: Ultra-deep desulfurization of FCC gasoline with min-imal octane penalty using Prime-G+ process.

Description: FCC debutanizer bottoms are fed directly to the firstreactor, wherein under mild conditions diolefins are selectivelyhydrogenated, and mercaptans are converted to heavier sulfurspecies. The selective hydrogenation reactor effluent is then usually

split to produce a light cat naphtha (LCN) cut and a heavy cat naph-tha (HCN). The LCN stream is mercaptans-free with a low sulfur anddiolefin concentration enabling further processing in an etherifica-tion or alkylation unit. The HCN then enters the main Prime-G+ sec-tion, where it undergoes in a dual catalyst system a deep HDS withvery limited olefins saturation and no aromatics losses to producean ultra-low sulfur gasoline. Pool sulfur specifications as low asless than 10 ppm can be attained with the Prime-G+ process.

Full-range FCC gasoline, Feed Prime-G+40°C–220°C product

Sulfur, ppm 2,000 50*RON 91 88.8MON 79 78.2(RON + MON)/2 85 83.5∆ (RON + MON)/2 1.5% HDS 97.5

* ≤ 30 ppm pool sulfur after blending.

Economics:Investment: Grassroots ISBL cost: 600 – 800 $/bpsdCombined utilities: 0.32 $/bblHydrogen: 0.28 $/bblCatalyst: 0.03 $/bbl

Installation: Thirteen Prime-G+ 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 and IFP North America.

START

Selectivehydro.

Prime-G+dual catalyst

reactor systemFeed

HCN

Splitter(optional)

Stabilizer

Fuel gas

LCN to TAME or alky. unit

Ultra-lowsulfur

gasoline

Hydrogenmakeup



HydrocrackingApplication: Desulfurization, demetallization, CCR reduction, and hydro-cracking of atmospheric and vacuum resids using the LC-Fining process.

Products: Full range of high quality distillates. Residual productscan be used as fuel oil, synthetic crude or feedstock for a resid FCC,coker, visbreaker or solvent deasphalter.

Description: Fresh hydrocarbon liquid feed is mixed with hydrogenand reacted within an expanded catalyst bed (1) maintained in tur-bulence by liquid upflow to achieve efficient isothermal operation. Prod-uct quality is maintained constant and at a high level by intermittentcatalyst addition and withdrawal. Reactor products flow to a high-pres-sure separator (2), low-pressure separator (3) and product fractiona-tor (4). Recycle hydrogen is separated (5) and purified (6).

Process features include on stream catalyst addition and with-drawal. Recovering and purifying the recycled H2 at low pressure

rather than at high pressure can result in lower capital cost andallows design at lower gas rates.

Operating conditions: Typical reactor temp., 725°F to 840°F; reac-tor press., 1,400 to 3,500 psig; H2 part. press., 1,000 to 2,700 psig;LHSV, 0.1 to 0.6; conversion, 40% to 97+%; desulfurization, 60% to90%; demetallization, 50% to 98%; CCR reduction, 35% to 80%.

Yields: For Arabian Heavy/Arabian Light blends:Feed Atm. resid Vac. residGravity, °API 12.40 4.73 4.73 4.73Sulfur, wt% 3.90 4.97 4.97 4.97Ni/V, ppmw 18/65 39/142 39/142 39/142Conversion vol%

(1,022°F+) 45 60 75 95Products, vol%C4 1.11 2.35 3.57 5.53C5–350°F 6.89 12.60 18.25 23.86350–700°F (650°F) (15.24) 30.62 42.65 64.81700 (650°F)–1,022°F (55.27) 21.46 19.32 11.921,022°F+ 25.33 40.00 25.00 5.0C5

+°API/wt%S 23.7/0.54 22.5/0.71 26.6/0.66 33.3/0.33

Economics: Investment,estimated (U.S. Gulf Coast, 2000)Size, bpsd fresh feed 92,000 49,000$ per bpsd(typical) fresh feed 2,200 3,500 4,200 5,200Utilities, per bbl fresh feedFuel fired, 103Btu 56.1 62.8 69.8 88.6Electricity, kWh 8.4 13.9 16.5 22.9Steam (export), lb 35.5 69.2 97.0 97.7Water, cooling, gal 64.2 163 164 248

Installation: Four LC-Fining units and three using Oxy Research& Development Co. technology. Another is under construction/designfor Shell Canada. Sizes: 6,000 to 80,000 bpsd.

Licensor: ABB Lummus Global Inc., Oxy Research & Develop-ment Co. and BP Corp.

1

Products

High-pressuresection

Low-pressuresection

2

3

6

5

4

Makeup hydrogen

LC-Finingreactor

Stm. RecycleH2

START

Hydrocarbonfeed



HydrocrackingApplication: Convert naphthas, AGO, VGO and cracked oils fromFCCs, cokers, hydroprocessing plants and SDA plants using theChevron ISOCRACKING process.

Products: Lighter, high-quality, more valuable products: LPG, gaso-line, catalytic reformer feed, jet fuel, kerosine, diesel, lube oils andfeeds for FCC or ethylene plants.

Description: A broad range of both amorphous/zeolite and zeolitecatalysts are used to obtain an exact match with the refiner’s pro-cess objective. An extensive range of proprietary amorphous/zeoliticcatalysts and various process configurations are used to match therefiner’s process objectives. Generally, a staged reactor system con-sists of one reactor (1, 4) and one HP separator (2, 5) per stageoptional recycle scrubber (3), LP separator (6) and fractionator (7)

to provide flexibility to vary the light-to-heavy product ratio andobtain maximum catalytic efficiency. Single-stage options (bothonce-through and recycle) are also used when economical.

Yields: Typical from various feeds:Feed Naphtha LCCO VGO VGOCatalyst stages 1 2 2 2Gravity, °API 72.5 24.6 25.8 21.6ASTM 10%/EP, °F 154/290 478/632 740/1,050 740/1,100Sulfur, wt% 0.005 0.6 1.0 2.5Nitrogen, ppm 0.1 500 1,000 900Yields, vol%Propane 55 3.4 — —iso-Butane 29 9.1 3.0 2.5n-Butane 19 4.5 3.0 2.5Light naphtha 23 30.0 11.9 7.0Heavy naphtha — 78.7 14.2 7.0Kerosine — — 86.8 48.0Diesel — — — 50.0Product qualityKerosine smoke pt., mm — — 28 28Diesel Cetane index — — — 58Kerosine freeze pt., °F — — 465 475Diesel pour pt., °F — — — 410

Economics:Investment (basis: 30,000 bpsd maximum conversion unit, Mid-East VGO feed, includes only on-plot facilities and first catalystcharge, 1994 U.S. Gulf Coast), $ per bpsd 2,800Utilities, typical per bbl feed:Fuel, equiv. fuel oil, gal 1Electricity, kWh 7Steam, 150 psig (net produced), lb (50)Water, cooling, gal 330

Installation: More than 50 units exceeding 750,000 bpsd total capacity.

Licensor: Chevron Research and Technology Co. Available throughChevron Products Co. (Technology Marketing) and ABB LummusGlobal Inc.

Feed2 5 6

7

341

START

Makeuphydrogen

Washwater

H2SProcess gas

Light naphtha

Heavy naphtha

Kerosine

Diesel

Sour water



HydrocrackingApplication: Upgrade vacuum gas oil alone or blended with variousfeedstocks (light-cycle oil, deasphalted oil, visbreaker or coker-gas oil).

Products: Middle distillates, very-low-sulfur fuel oil, extra-qualityFCC feed or high VI lube base stocks.

Description: This process uses a refining catalyst usually followedby a zeolite-type hydrocracking catalyst. Main features of this pro-cess are:

• High tolerance toward feedstock nitrogen• High selectivity toward middle distillates• High activity of the zeolite, allowing for 3–4 year cycle lengths

and products with low aromatics content until end of cycle.

Three different process arrangements are available: single-step/once-through; single-step/total conversion with liquid recycle;and two-step hydrocracking. The process consists of: reaction section(1, 2), gas separator (3), stripper (4) and product fractionator (5).

Product quality: Typical for HVGO (50/50 Arabian light/heavy):Feed, JetHVGO fuel Diesel

Sp. gr. 0.932 0.800 0.826TBP cut point, °C 405–565 140–225 225–360Sulfur, ppm 31,700 < 10 < 10Nitrogen, ppm 853 < 5 < 5Metals, ppm < 2 – –Cetane index – – 62Flash pt., °C – ≥ 40 125Smoke pt., mm, EOR – 26–28 –Aromatics, vol%, EOR – < 12 < 8Viscosity @ 38°C, cSt 110 – 5.3PAH, wt%, EOR <2

Economics:Investment (basis: 40,000-bpsd unit, once-through, 90% con-

version, battery limits, erected, engineering fees included,2000 Gulf Coast), $ per bpsd 2,500–3,000

Utilities, typical per bbl feed:Fuel oil, kg 5.3Electricity, kWh 6.9Water, cooling, m3 0.64Steam, MP balance

Installation: Forty references, cumulative capacity exceeding1,000,000 bpsd, conversion ranging from 20% to 99%.

Licensor: IFP.

H2makeup

Fuel gas Fuel gas

Lightgas oil

Diesel

Wild naphtha

Low-sulfur fuel oilFeed

START

3 45

1 2



HydrocrackingApplication: Convert a wide variety of feedstocks including vacuumgas oil, coker gas oils and FCC cycle oils into high-quality, low-sul-fur fuels using the MAKFining HDC process.

Products: A wide range of high-quality, low-sulfur distillate fuels andblending stocks including LPG, high-octane gasoline, reformer naphtha,jet fuel, kerosine and diesel fuel. Unconverted products from single-passoperations are excellent feedstocks for fluid catalytic cracking, lube oilbasestock production, steam cracking and low-sulfur fuel oil.

Description: MAKFining HDC technology is a product of an alliancebetween ExxonMobil, Akzo Nobel, Kellogg Brown & Root and FinaResearch S.A. The process uses a multiple catalyst system in multi-bed reactors that incorporate proprietary advanced quench and

redistribution internals (Spider Vortex Quench Zone Technology). Feedand recycle gas are preheated and contact the catalyst in the down-flow fixed-bed reactor (1). Reactor effluent is flashed in high and lowtemperature separators, (2) and (3). An amine contactor tower (4)scrubs H2S from recycle gas. A simple stripper/fractionator arrange-ment is shown for product recovery (5) and (6).

Operating conditions: Typical operating conditions are categorizedaccording to either single-pass or extinction recycle configurations:

Single pass RecycleTemperature, °F 700–800 700–800Pressure, psig 1,000–2,000 1,500–3,000

Yields: Typical operation on Middle East VGO and FCC LCO.Feed AL/AH VGO LCOGravity, °API 20.2 19.0ASTM FBP, °F 1,050 620Sulfur, wt% 2.9 1.0Nitrogen, ppmw 900 600Cetane index — 28Conversion 50% 70% 98% 50%Naphtha, vol% 12.9 22.6 17.2 54.0Kerosine, vol% 14.1 24.5 26.9 —Diesel, vol% 31.8 32.5 63.6 54.3LSGO, vol% 50.0 30 2.2 —H2 consumed, scf/bbl 1,080 1,300 1,525 1,730Product QualityNaphtha, RON 64 63 66 92Diesel cetane index 53 55 61 39Diesel sulfur, ppmw <30 < 10 <10 <10

Economics: Investment, $ per bpsd 2,000–4,000

Installation: Four operating units. One unit in design.

Reference: Paper AM-94-21, NPRA meeting, March 20–22, 1994.


Feedwash H2S

Feed

Makeuphydrogen

Naphtha

Fuelgas

Kerosine

Diesel

Low-sulfur HGORecycle oil

Naphtha

START

1

2

4

3

5

6



HydrocrackingApplication: The Shell hydrocracking process converts heavy VGOand other low-cost cracked and extracted feedstocks to high-value,high-quality products. Profitability is maximized by careful choiceof process configuration, conditions and catalyst system to matchrefiners’ product quality and selectivity requirements.

Products: Low-sulfur diesel and jet fuel with excellent combustionproperties, high-octane light gasoline, and high-quality reformer, catcracker or lube oil feedstocks.

Description: Heavy hydrocarbons are discharged to the reactorcircuit and preheated with reactor effluent (1). Fresh hydrogen is dis-charged to the reactor circuit and combined with recycle gas from thecold high-pressure separator. The mixed gas is supplied as quenchfor reactor interbed cooling with the balance first preheated with reac-tor effluent followed by further heating in a single phase furnace. Aftermixing with the liquid feed, the reactants pass in trickle flow throughthe multi-bed reactor(s) which contains proprietary pre-treat, crack-ing and post-treat catalysts (2). Interbed ultra-flat quench internalsand high dispersion nozzle trays combine excellent quench, mixingand liquid flow distribution at the top of each catalyst bed while max-imizing reactor volume utilization. After cooling by incoming feedstreams, reactor effluent enters a four-separator system from whichhot effluent is routed to the fractionator (3). Wash water is appliedvia the cold separators in a novel countercurrent configuration toscrub the effluent of corrosive salts and avoid equipment corrosion.

Two-stage, series flow and single-stage unit design configurationsare all available including the single reactor stacked catalyst bedwhich is suitable for capacities up to 10,000 tpd in partial or full con-version modes. The catalyst system is carefully tailored for thedesired product slate and cycle run length.

Installation: Over 20 new distillate and lube oil units including tworecent single-reactor high-capacity stacked bed units. Over a dozenrevamps have been carried out on own and other licensor designs usu-ally to debottleneck and increase feed heaviness.

References: “Performance optimisation of trickle bed processes,”European Refining Technology Conference, Berlin, November 1998;“Design and operation of Shell single reactor hydrocrackers,” 3rdInternational Petroleum Conference, New Delhi, January 1999.


STARTBleed

370–

370+Feed

Recyclecompressor

Recycle gasFresh gas

Quench gasCHPseparator

HLPseparator

HHPseparator

CLPseparator

Fractionator

2

1

3



HydrocrackingApplication: Convert a wide variety of feedstocks into lower-molec-ular-weight products using the Unicracking process.

Feed: Feedstocks include atmospheric gas oil, vacuum gas oil,FCC/RCC cycle oil, coker gas oil, deasphalted oil and naphtha for pro-duction of LPG.

Products: Processing objectives include production of gasoline, jetfuel, diesel fuel, lube stocks, ethylene-plant feedstock, high-qualityFCC feedstock and LPG.

Description: Feed and hydrogen are contacted with catalysts,which induce desulfurization, denitrogenation and hydrocracking.

Catalysts are based upon both amorphous and molecular-sieve con-taining supports. Process objectives determine catalyst selection fora specific unit. Product from the reactor section is condensed, sep-arated from hydrogen-rich gas and fractionated into desired products.Unconverted oil is recycled or used as lube stock, FCC feedstock orethylene-plant feedstock.

Yields: Example:FCC cycle Vacuum Fluid coker

Feed type oil blend gas oil gas oilGravity, °API 27.8 22.7 8.4Boiling, 10%, °F 481 690 640End pt., °F 674 1,015 1,100Sulfur, wt% 0.54 2.4 4.57Nitrogen, wt% 0.024 0.08 0.269Principal products Gasoline Jet Diesel FCC feedYields, vol% of feedButanes 16.0 6.3 3.8 5.2Light gasoline 33.0 12.9 7.9 8.8Heavy naphtha 75.0 11.0 9.4 31.8Jet fuel 89.0Diesel fuel 94.1 33.8600°F + gas oil 35.0H2 consump., scf/bbl 2,150 1,860 1,550 2,500

Economics: Example:Investment, $ per bpsd capacity 2,000–4,000Utilities, typical per bbl feed:Fuel, 103 Btu 120–150Electricity, kWh 8–12

Installation: Selected for 142 commercial units, including severalconverted from competing technologies. Total capacity exceeds 2.9 mil-lion bpsd.

Licensors: UOP LLC.

START Sour water

To fractionator

To fractionator

Flash gas

Makeuphydrogen

Washwater

3

4

5

12

Fresh feed

Recycle oil



HydrocrackingApplication: Upgrading of heavy and extra heavy crudes as well asresidual oils.

Products: Full-range high quality syncrude.

Description: A hydrogen addition process applying the principlesof thermal hydrocracking in liquid-phase hydrogenation reactors(LPH) (1) for primary conversion directly coupled with an integratedcatalytical hydrofinishing step (GPH). In the LPH slurry phasereactors, residue is converted up to 95% at temperatures between440°C and 500°C. In the hot separator (HS) (2), light distillates areseparated from the unconverted material. By vacuum-flash distil-lation (3) the HS bottoms distillates are recovered. For furtherhydrotreating, the HS overheads, together with the recovered HS bot-

toms distillates and straight run distillates (optional), are routed tothe catalytical fixed-bed reactors of the GPH (4), which operates atthe same pressure as the LPH. GPH pressure is typically abovehydrocracking conditions, therefore, GPH mild hydrocracking can alsobe applied to allow a shift in yield structure to lighter products. Sep-aration of syncrude and associated gases is performed in a cold sep-arator system (5). The syncrude after separation is sent to a stabi-lizer (6) and a fractionation unit. After being washed in a lean oilscrubber (7), the gases are recycled to the LPH section.

Feed: Feedstock quality ranges covered are:Gravity, °API −3 to 14Sulfur, wt% 0.7 to 7Metals (Ni,V), ppm up to 2,180Asphaltenes, wt% 2 to 80

Yields: Naphtha < 180°C, wt% 15–30Middle distillates, wt% 35–40Vac. gasoil > 350°C, wt% 15–30

Product qualities:Naphtha: Sulfur <5 ppm, Nitrogen <5 ppmKerosine: Smoke point >20 mm, Cloud point <−50°CDiesel: Sulfur <50 ppm, Cetane no >45Vac. gasoil: Sulfur <150 ppm, CCR <0.1wt%, Metals <1 ppm

Economics: Plant capacity 23,000 bpsd.Investment U.S. MM$190 (US Gulf Coast, 1st Q. 1994)Utilities:Fuel oil, MW 12Power, MW 17Steam, tph -34Water, cooling, m3/h 2,000

Installation: Two licenses have been granted.

Licensor: VEBA OEL Technologie und Automatisierung GmbH.

Straight run distillates

Vacuum residue

Hydrogenation residue

Waste water

Syn-crude

65

721

3

Additive

Hydrogen

Offgas

Recyclegas

4



Hydrocracking, residueApplication: Catalytic hydrocracking and desulfurization of residuaand heavy oils in an ebullated-bed reactor using the H-Oil process.

Products: Full-range distillates and upgraded residue, trans-portation fuels, FCC or coker feed, low-sulfur-fuel oil.

Description: A one, two or three stage ebullated-bed (1) reactor sys-tem. Feed consists of atmospheric or vacuum residue, recycle fromdownstream fractionation (3), hydrogen-rich recycle gas and makeuphydrogen. Combined feed is fed to the bottom of the reactor andexpands the catalyst bed resulting in good mixing, near isothermaloperation and allows for onstream catalyst replacement to maintaincatalyst activity and 3 to 4 year run lengths between turnarounds.Two-phase reactor effluent is sent to high-pressure separator (2); liq-uid is sent to fractionation (3) to recover light liquid products and vac-

uum bottoms for recycle.

Operating conditions: Temperature, 770°F–840°F; hydrogen par-tial pressure, psi 1,000–2,500; LHSV, 0.1–1.0 hr –1; conversion30%–90%.

Process performance and yields: From commercial two-stageprocessing:

Vacuum residue conversion 52 W% 70 W%Processing objective LSFO ConversionFeed Ural VR Arab H VR+FCC slurry

Gravity, ºAPI 13 3.61,000ºF+, vol% 85 85Sulfur, wt% 2.8 5.2

Performance, yields and product qualitiesHDS, wt% 85 83HDN, wt% 40 38Chem. H2 Cons, scf/bbl 920 1,540Naphtha, vol% 7 8Diesel, vol% 25 33VGO, vol% 31 38Residue, vol% 41 25Diesel sulfur, wppm 400 2,000VGO sulfur, wt% 0.18 0.9Residue sulfur, wt% 0.8 2.0Residue gravity, ºAPI 14 4.0

Economics: Basis 2000 U.S. Gulf CoastInvestment—$ per bpsd 3,000–5,000Utilities—per bbl of feed Fuel, 103 Btu 40–100Power, kWh 9–15Water, cooling (20°F rise), gal 100–200Catalyst makeup, $ 0.2–1.5

Installation: Seven units currently in operation.

Licensor: IFP, IFP North America.

Purge toH2 recovery

31

2

1 1

Vacuum bottoms tofuel oil, coker, etc.

CatalystwithdrawalVacuum residue

feedstock

Catalyst

Fuel gasNaphthaMiddle distillateto diesel poolVGO to FCC

H2makeup

START



Hydrocracking/hydrotreating—VGOApplication: The T-Star Process is an ebullated-bed process for thehydrotreatment/hydrocracking of vacuum gas oils. The T-Star Pro-cess is best suited for difficult feedstocks (coker VGO, DAO), high-severity operations and applications requiring a long run length.

Description: A T-Star process flow diagram, which includes inte-grated mid-distillate hydrotreating, is shown above. The typical T-Star battery limits include oil/hydrogen fired heaters, an advancedhot high-pressure design for product separation and for providing recy-cle to the ebullating pump, recycle gas scrubbing and product sep-aration. Catalyst is replaced periodically from the reactor, without

shutdown. This ensures the maintenance of constant, optimal cat-alyst activity and consistent product slate and quality. After high-pressure recovery of the effluent and recycle gas, the products areseparated and stabilized through fractionation. A T-Star unit can oper-ate for four-year run lengths with conversion in the 20%–60% rangeand hydrodesulfurization in the 93%–99% range.

Operating conditions:

Temperature, °F 750–820Hydrogen partial pressure, psi 600–1,500LHSV, hr –1 0.5–3.0VGO conversion, % 20–60

Examples: In Case 1, a deep-cut Arab heavy VGO is processed at40 wt% conversion with objectives of mild conversion and preparingspecification diesel and FCC unit feed. In Case 2, a VGO blend con-taining 20% coker material is processed at lower conversion to alsoobtain specification FCC unit feedstock and high-quality diesel.

Economics: Basis 2000 U.S. Gulf CoastInvestment in $ per bpsd 1,200–2,500Utilities—per bbl of feed

Fuel, 103 Btu 60Power, kWh 3Catalyst makeup, $ 0.05–0.20

Installation: The T-Star process is commercially demonstratedbased on the ebullated-bed reactor. IFP has licensed more than 1.3MMbpsd of capacity in gas oil, VGO and residue. IFP has seven com-mercially operating ebullated-bed units and one is under construc-tion that will process a variety of VGO feedstocks.

Reference: “A Novel Approach to Attain New Fuel Specifications,”Petroleum Technology Quarterly, Winter 1999/2000.

Licensor: IFP, IFP North America.

START

VGO feed

Oil feedheater

T-starreactor High

pressureseparator

Recycle hydrogencompressor

Recycle hydrogen

Makeup hydrogen

Ebullatingpump

Gas-oilstripper FCC feed S=

1,000-1,500 wppm

Diesel S=<50 wppm

Fuel gas

Fixed-bedHDS

Stabilizer

Amineabsorber

Naphtha S=<2 wppm

Hydrogenheater



HydrodearomatizationApplication: Topsøe’s two-stage hydrodesulfurization hydrodearom-atization (HDS /HDA) process is designed to produce low-aromaticsdistillate products. This process enables refiners to meet the new,stringent standards for environmentally friendly fuels.

Products: Ultra-low sulfur, ultra-low nitrogen, low-aromatics diesel,kerosine and solvents (ultra-low aromatics).

Description: The process consists of four sections: initial hydrotreating,intermediate stripping, final hydrotreating and product stripping. Theinitial hydrotreating step, or the “first stage” of the two-stage reaction pro-cess, is similar to conventional Topsøe hydrotreating, using a Topsøe high-activity base metal catalyst such as TK-573 to perform deep desulfuriza-tion and deep denitrification of the distillate feed. Liquid effluent from thisfirst stage is sent to an intermediate stripping section, in which H2S andammonia are removed using steam or recycle hydrogen. Stripped distillate

is sent to the final hydrotreating reactor, or the “second stage.” In this reac-tor, distillate feed undergoes saturation of aromatics using a Topsøe noblemetal catalyst, either TK-907/ TK-908 or TK-915, a newly developed high-activity dearomatization catalyst. Finally, the desulfurized, dearomatizeddistillate product is steam stripped in the product stripping column to removeH2S, dissolved gases and a small amount of naphtha formed.

Like the conventional Topsøe hydrotreating process, the HDS/HDA pro-cess uses Topsøe’s graded bed loading and high-efficiency patented reactorinternals to provide optimum reactor performance and catalyst use lead-ing to the longest possible catalyst cycle lengths. Topsøe’s high efficiencyinternals have a low sensitivity to unlevelness and are designed to ensure themost effective mixing of liquid and vapor streams and maximum utiliza-tion of catalyst. These internals are effective at high of liquid loadings,thereby enabling high turndown ratios. Topsøe’s graded-bed technology andthe use of shape-optimized inert topping and catalysts minimize the build-up of pressure drop, thereby enabling longer catalyst cycle length.Operating conditions: Typical operating pressures range from 20to 60 barg (300 to 900 psig), and typical operating temperatures rangefrom 320°C to 400°C (600°F to 750°F) in the first stage reactor, andfrom 260°C to 330°C (500°F to 625°F) in the second stage reactor. TheTopsøe HDS/HDA treatment of a heavy straight-run gas oil feedyielded these product specifications:

Feed ProductSpecific gravity 0.86 0.83Sulfur, ppmw 3,000 1Nitrogen, ppmw 400 <1Total aromatics, wt% 30 <10Cetane index, D-976 49 57

References: Cooper, Hannerup and Søgaard-Andersen, “Reduc-tion of Aromatics in Diesel,” Oil and Gas, September 1994

Søgaard-Andersen, Cooper and Hannerup, “Topsøe’s Process forImproving Diesel Quality,” NPRA Annual Meeting, 1992.

de la Fuente, E., P. Christensen, and M. Johansen, “Options formeeting EU year 2005 fuel specifications.”Installation: A total of four, two in Europe and two in North America.Licensor: Haldor Topsøe A/S.

Dieselfeed

Makeup hydrogen

Firststage

HDSreactor

HDAreactorSecond

stage

HDSstripper

HDAseparator

Diesel product

Wildnaphtha

Water

Overheadvapor

Steam

Diesel cooler

Washwater

Aminescrubber

Recycle gascompressor

HDSstripper

Productdiesel

stripper

Sourwater

HDS s

epar

ator



HydrodesulfurizationApplication: The ISAL process enables refiners to meet the world’smost stringent specifications for gasoline sulfur and olefin content.This low-pressure, fixed-bed hydroprocessing technology desulfur-izes gasoline-range feedstocks and selectively reconfigures loweroctane components to control product octane.

Description: The flow scheme of the ISAL process is very similarto that of a conventional hydrotreating process. The naphtha feed is

mixed with hydrogen-rich recycle gas and processed across fixed cat-alyst beds at moderate temperatures and pressures. Following heatexchange and separation, the reactor effluent is stabilized. The sim-ilarity of an ISAL unit to a conventional naphtha hydrotreatingunit makes implementation both simple and straightforward. Thetechnology can be applied to idle reforming and hydrotreating units.

Product quality: The unit operation can be adjusted to optimize var-ious desulfurization, octane and yield combinations.

Hydro- ISALProperty Feed treater Case A Case B Case CAPI° 47.3 48.1 48.7 48.5 48.5Sulfur, wppm 2,160 25 25 25 <5Olefins vol% 27.6 <1 <1 <1 <1C5

+ vol% 100.1 99.7 98.0 97R+M/2 octane

change -8.9 -1.5 0 0

Economics: The capital and operating costs of an ISAL unit are onlyslightly higher than those of a typical naphtha hydrotreating unit.With this process, refiners benefit from a higher-octane productwith minimal additional operating cost. A payback period of less thanone year is expected on the small incremental investment for ISALover that for conventional hydrotreating.

Installations: The first ISAL process unit is a reload of an existinghydrotreater for a U.S. Gulf Coast refinery that started operation inSeptember 2000. As of October 2000, two revamp applications andtwo new units are in the engineering phase.

Licensor: UOP LLC (in cooperation with PDVSA-INTEVEP).

4

3

Wash water

Sour water

Hydrogen makeup

Fresh feed

Light ends

Low-sulfurnaphtha

1

2



Hydrodesulfurization—UDHDSApplication: A versatile family of MAKFining Premium DistillatesTechnologies (PDT) is used to meet all current and possible futurepremium diesel upgrading requirements. Ultra-deep hydrodesulfu-rization (UDHDS) process can produce distillate products with sul-fur levels below 10 wppm from a wide range of distillate feedstocks.

Products: High volume yield of ultra-low-sulfur distillate is produced.

A small cetane and API gravity uplift together with the reduction ofpolyaromatics to less than 11 wt% or as low as 5 wt% can be eco-nomically achieved.

Description: MAKFining technology is offered through the globalhydroprocessing alliance between ExxonMobil Research and Engi-neering, Akzo Nobel Chemicals, Kellogg Brown & Root and FinaResearch S.A. MAKFining PDT units combine a family of technolo-gies in low-cost integrated designs to achieve the necessary productuplift. The first step for any PDT unit is ultra-deep HDS. A single-stage, single-reactor process incorporates proprietary high-perfor-mance-distribution and advanced-quench internals. Feed and com-bined recycle and makeup gas are preheated and contact the catalystin a downflow-concurrent-fixed-bed reactor. The reactor effluent isflashed in a high- and a low-pressure separator. An amine absorbertower is used to remove H2S from the recycle gas. In the exampleshown, a steam stripper is used for final product recovery. TheMAKFining UDHDS technology is equally applicable to revampand grassroots applications.

Economics: Investment (basis: 25,000 to 35,000 bpsd, 1st quarter2000 U.S. Gulf Coast)

New unit, $ per bpsd 1,000 to 1,800

Installation: Thirty-six distillate-upgrading units have applied theMAKFining Premium Distillates Technologies. Eleven of these appli-cations are revamps.

Reference: “MAKFining—Premium Distillates Technology: TheFuture of Distillate Upgrading,” Paper AM-00-18, NPRA AnnualMeeting, March 2000, San Antonio.

Licensor: Akzo Nobel and Kellogg Brown & Root, Inc.

Distillatefeed

Steam

Naphtha

Hot s

epar

ator

ProductstripperCharge

pump

Absorber

Lean amineFuelgas

Rich amine

Low-sulfurdiesel

Hydrogen

Water wash

Sour water

UDHDSreactor

Makeupcompressor

Coldseparator

Recyclecompressor

Heater



HydrogenationApplication: CDHydro is used to selectively hydrogenate diolefinsin the top section of a hydrocarbon distillation column. Additionalapplications—including mercaptan removal, hydroisomerizationand hydrogenation of olefins and aromatics are also available.

Description: The patented process CDHydro combines fractionationwith hydrogenation. Proprietary devices containing catalyst areinstalled in the fractionation column’s top section (1). Hydrogen isintroduced beneath the catalyst zone. Fractionation carries lightcomponents into the catalyst zone where the reaction with hydrogenoccurs. Fractionation also sends heavy materials to the bottom. Thisprevents foulants and heavy catalyst poisons in the feed from con-tacting the catalyst. In addition, clean hydrogenated reflux contin-uously washes the catalyst zone. These factors combine to give a long

catalyst life. Additionally, mercaptans can react with diolefins to makeheavy, thermally-stable sulfides. The sulfides are fractionated to thebottoms product. This can eliminate the need for a separate mer-captan removal step. The distillate product is ideal feedstock for alky-lation or etherification processes.

The heat of reaction evaporates liquid, and the resulting vaporis condensed in the overhead condenser (2) to provide additionalreflux. The natural temperature profile in the fractionation columnresults in a virtually isothermal catalyst bed rather than the tem-perature increase typical of conventional reactors.

The CDHydro process can operate at much lower pressure thanconventional processes. Pressures for CDHydro are typically set bythe fractionation requirements. Additionally, the elimination of aseparate hydrogenation reactor and hydrogen stripper offer signifi-cant capital cost reduction relative to conventional technologies.

Feeding CDHydro with reformate and light-straight run for ben-zene saturation provides the refiner with increased flexibility to pro-duce RFG. Isomerization of the resulting C5/C6 overhead stream pro-vides higher octane and yield due to reduced benzene and C7+ contentcompared to typical isomerization feedstocks.

Economics: Fixed-bed hydrogenation requires a distillation columnfollowed by a fixed-bed hydrogenation unit. CDHydro eliminates thefixed-bed unit by incorporating catalyst in the column. When a newdistillation column is used, capital cost of the column is only 5% to20% more than for a standard column depending on the CDHydroapplication. Elimination of the fixed-bed reactor and stripper canreduce capital cost by as much as 50%.

Installation: Fourteen CDHydro units are in commercial operationfor C4, C5, C6 and benzene hydrogenation applications. Three unitshave been in operation for more than five years and total commer-cial operating time now exceeds 50 years for CDHydro technologies.Twelve additional units are currently in engineering/construction.

Licensor: CDTECH.

1Hydrogen

Reflux Treated FCC C4sMPsteam

Depentanizer

FCC C4+

CW

Hydrogen recycle

Off gas

FCC C5+ gasoline

2



HydrotreatingApplication: Hydroprocessing of middle distillates, including crackedmaterials (coker/visbreaker gas oils and LCO) using SynTechnology, max-imizes distillate yield while producing ultra-low-sulfur diesel with improvedcetane and API gain, reduced aromatics, T95 reduction and cold-flowimprovement through selective ring opening, saturation and/or isomer-ization. Various process configurations are available for revamps and newunit design to stage investments to meet changing diesel specifications.

Products: Maximum yield of improved quality distillate while min-imizing fuel gas and naphtha. Diesel properties include less than 10-ppm sulfur, with aromatics content (total and/or PNA), cetane, den-sity and T95 dependent on product objectives and feedstock.

Description: SynTechnology includes SynHDS for ultra-deep desul-furization and SynShift/SynSat for cetane improvement, aromatics sat-uration and density/ T95 reduction. SynFlow for cold flow improve-

ment can be added as required. The process combines ABB LummusGlobal’s cocurrent and/or patented countercurrent reactor technology withspecial SynCat catalysts from Criterion Catalyst Co. LP. It incorporatesdesign and operations experience from Shell Global Solutions, to max-imize reactor performance by using advanced reactor internals.

A single-stage or integrated two-stage reactor system providesvarious process configuration options and revamp opportunities. In atwo-stage reactor system, the feed, makeup and recycle gas are heatedand fed to a first-stage cocurrent reactor. Effluent from the first stageis stripped to remove impurities and light ends before being sent to thesecond-stage countercurrent reactor. When a countercurrent reactoris used, fresh makeup hydrogen can be introduced at the bottom ofthe catalyst bed to achieve optimum reaction conditions.

Operating conditions: Typical operating conditions range from 500–1,000psig and 600°F–750°F. Feedstocks range from straight-run gas oils to feedblends containing up to 70% cracked feedstocks that have been com-mercially processed. For example, the SynShift upgrading of a feed blendcontaining 72% LCO and LCGO gave these performance figures:

Feed blend ProductGravity, °API 25 33.1Sulfur, wt% (wppm) 1.52 (2)Nitrogen, wppm 631 <1Aromatics, vol% 64.7 34.3Cetane index 34.2 43.7Liquid yield on feed, vol% 107.5

Economics: SynTechnology encompasses a family of low-to-moderatepressure processes. Investment cost will be greatly dependent on feedquality and hydroprocessing objectives. For a 30,000 to 35,000-bpsdunit, the typical ISBL investment cost in U.S.$/bpsd (U.S. GulfCoast 2000) are:

Revamp existing unit 450–950New unit for deep HDS 1,100–1,200New unit for cetane improvement and HDA 1,500–1,600

Installation: SynTechnology has been selected for more than 30 units,with half of the projects being revamps. Seven units are in operation.

Licensor: ABB Lummus Global, Inc., on behalf of the SynAlliance,which includes Criterion Catalyst Co. LP, and Shell Global Solutions.

Feed oil

First stagereactor

Interstagestripper

Second stagereactor

Product tostripping

H2rich gas

Vapor/liquidseparation/recycle



HydrotreatingApplication: CDHydro and CDHDS are used to selectively desul-furize FCC gasoline with minimum octane loss.

Products: Ultra-low-sulfur FCC gasoline with maximum retentionof olefins and octane.

Description: The light, mid and heavy cat naphthas (LCN, MCN,HCN) are treated separately, under optimal conditions for each.The full-range FCC gasoline sulfur reduction begins with fraction-ation of the light naphtha overhead in a CDHydro column. Mercaptansulfur reacts quantitatively with excess diolefins to product heaviersulfur compounds, and the remaining diolefins are partially saturatedto olefins by reaction with hydrogen. Bottoms from the CDHydro col-umn, containing the reacted mercaptans, are fed to the CDHDScolumn where the MCN and HCN are catalytically desulfurized in

two separate zones. HDS conditions are optimized for each fractionto achieve the desired sulfur reduction with minimal olefin satura-tion. Olefins are concentrated at the top of the column, where con-ditions are mild, while sulfur is concentrated at the bottom wherethe conditions result in very high levels of HDS.

No cracking reactions occur at the mild conditions, so that yieldlosses are easily minimized with vent-gas recovery. The three prod-uct streams are stabilized together or separately, as desired, result-ing in product streams appropriate for their subsequent use. Thetwo columns are heat integrated to minimize energy requirements.Typical reformer hydrogen is used in both columns without makeupcompression. Optimal integration with hydrogen generation andsour-gas treating facilities at some sites may result in the inclusionof hydrogen recycle and vent-gas treating within the process. Thesulfur reduction achieved will allow the blending of gasoline thatmeets current and future regulations.

Catalytic distillation essentially eliminates catalyst foulingbecause the fractionation removes heavy-coke precursors from thecatalyst zone before coke can form and foul the catalyst pores. Thus,catalyst life in catalytic distillation is increased significantly beyondtypical fixed-bed life. The CDHydro/CDHDS units can operatethroughout an FCC turnaround cycle up to five years without requir-ing a shutdown to regenerate or to replace catalyst.

Economics: The estimated ISBL capital cost for a 35,000 bpdCDHydro/CDHDS unit with 92% desulfurization is $25 million (2000U.S. Gulf Coast). Direct operating costs—including utilities, catalyst,hydrogen and octane replacement—are estimated at $0.03/gas of full-range FCC gasoline.

Installation: Three CDHydro units are in operation treating FCCgasoline and twelve more units are currently in engineering/con-struction. Two CDHDS units are in operation with six additional unitscurrently in engineering/construction.

Licensor: CDTECH.

HCN

MCN

LCN

MCN/HCN

CDHydro

CDHDS

Hydrogen

Hydrogen

FCC C5+ gasoline



HydrotreatingApplication: Hydrotreat atmospheric or vacuum residuum feedstocksto reduce sulfur, nitrogen, metals, asphaltene and carbon residue con-tents. To convert residuum into lighter products while reducing theviscosity of the unconverted bottoms using the RDS/VRDS hydrotreat-ing process.

Products: Residuum FCC unit feedstock, coker feedstock or low-sul-fur fuel oil. VGO product, if recovered, is suitable for further upgrad-ing in FCC units or hydrocrackers for gasoline/mid-distillate man-ufacture. Mid-distillate products are suitable for blending into dieselproduct.

The process integrates well with residuum FCC units to minimizecatalyst consumption and improve yields and with delayed coking,which minimizes quantity and improves coke quality. Processing dea-sphalted oil in a VRDS unit achieves high conversion to distillateproducts.

Description: Oil feed and hydrogen are charged to the reactor (1)in a once-through operation. Product separation is done by the hothigh-pressure separator (2), cold high-pressure separator (3) and frac-tionator (4). Recycle hydrogen passes through an H2S absorber (5).

A wide range of feedstocks can be processed. Existing units haveprocessed feeds with viscosities as high as 6,000 cSt at 100°C and met-als contents as high as 500 ppm.

Onstream catalyst replacement (OCR) technology allows spent cat-alyst to be removed from one or more reactors and replaced with freshcatalyst while all reactors operate normally. This allows very heavyfeedstocks to be processed with long run lengths (one year or more).

Installation: 22 RDS/VRDS hydrotreaters are operating, includinga 96,000-bpsd unit. Six VRDS units are operating including a 30,000-bpsd unit. Eleven RDS units pretreat residuum charged to RFCCunits. Three RDS units, one of which is a 50,000-bpsd unit, receivedemetallized residuum from OCR reactors. Two new RDS units andone revamp unit using Up Flow Reactor (UFR) technology are in engi-neering or under construction. Total current capacity is 894,000bpsd. Future additional RDS capacity is 148,000 bpsd.

Reference: Reynolds, “Resid Hydroprocessing with Chevron Tech-nology,” JPI, Tokyo, Japan, October 19, 1998. Reynolds and Brossard,“RDS/VRDS Hydrotreating Broadens Application of RFCC,” HTIQuarterly, Winter 1995/96.

Licensor: Chevron Research and Technology Co. Available through:Chevron Products Co. (Technology Marketing)

Sourwater

Hydrotreatedresid product

VGO

Middledistillate

Unstabilizednaphtha

Process gasH2SWash

water

Makeuphydrogen

Fresh feed

1

24

3

5

START



HydrotreatingApplication: Topsøe hydrotreating technology has a wide range ofapplications, including the purification of naphtha, distillates andresidue, as well as the deep desulfurization and color improvementof diesel fuel and pretreatment of FCC and hydrocracker feedstocks.

Products: Ultra-low-sulfur diesel fuel, and clean feedstocks forFCC and hydrocracker units.

Description: Topsøe’s hydrotreating process design incorporates ourindustrially proven high-activity TK catalysts with optimized graded-bed loading and high-performance, patented reactor internals. Thecombination of these features and custom design of hydrotreatingunits result in process solutions that meet the refiner’s objectives inthe most economic way.

In the Topsøe hydrotreater, feed is mixed with hydrogen, heatedand partially evaporated in a feed/effluent exchanger before it entersthe reactor. In the reactor, Topsøe’s high-efficiency internals have alow sensitivity to unlevelness and are designed to ensure the mosteffective mixing of liquid and vapor streams and the maximum uti-lization of the catalyst volume. These internals are effective at a highrange of liquid loadings, thereby enabling high turndown ratios. Top-søe’s graded-bed technology and the use of shape-optimized inerttopping and catalysts minimize the build-up of pressure drop, therebyenabling longer catalyst cycle length. The hydrotreating catalyststhemselves are of the Topsøe TK series, and have proven their highactivities and outstanding performance in numerous operating unitsthroughout the world. The reactor effluent is cooled in the feed-efflu-ent exchanger, and the gas and liquid are separated. The hydrogen gasis sent to an amine wash for removal of hydrogen sulfide and is thenrecycled to the reactor. Cold hydrogen recycle is used as quench gasbetween the catalyst beds, if required. The liquid product is steamstripped in a product stripper column to remove hydrogen sulfide,dissolved gases and light ends.

Operation conditions: Typical operating pressures range from 20to 80 barg (300 to 1,200 psig), and typical operating temperaturesrange from 320°C to 400°C (600°F to 750°F).

References: Bingham, Muller, Christensen and Moyse, “Perfor-mance Focused Reactor Design to Maximize Benefits of High Activ-ity Hydrotreating Catalysts,” European Refining Technology Con-ference, 1997.

Cooper, “Meeting the Challenge for Middle Distillates: Scientificand Industrial Aspects,” Petrotech, 1997.

de la Fuente, E., P. Christensen, and M. Johansen, “Options formeeting EU year 2005 fuel specifications.”

Installation: More than 30 Topsøe hydrotreating units for the var-ious applications above are in operation or in the design phase.

Licensor: Haldor Topsøe A/S.

START

Fresh feed

Product

Rich DEA

Lean DEA

H2 rich gas

Makeuphydrogen

Furnace

Reactor

Absorber

High-pressureseparator

Low-pressure separator



HydrotreatingApplication: Reduction of the sulfur, nitrogen, and metals contentof naphthas, kerosines, diesel or gas oil streams.

Products: Low-sulfur products for sale or additional processing.

Description: Single or multibed catalytic treatment of hydrocarbonliquids in the presence of hydrogen converts organic sulfur to hydro-gen sulfide and organic nitrogen to ammonia. Naphtha treatingnormally occurs in the vapor phase, and heavier oils usually oper-ate in mixed-phase. Multiple beds may be placed in a single reactorshell for purposes of redistribution and/or interbed quenching for heatremoval. Hydrogen-rich gas is usually recycled to the reactor(s) (1)to maintain adequate hyrogen-to-feed ratio. Depending on the sul-fur level in the feed, H2S may be scrubbed from the recycle gas. Prod-uct stripping is done with either a reboiler or with steam. Catalystsare cobalt-molybdenum, nickel-molybdenum, nickel-tungsten or acombination of the three.

Operating conditions: 550°F to 750°F and 400 to 1,500 psig reac-tor conditions.

Yields: Depend on feed characteristics and product specifications.Recovery of desired product almost always exceeds 98.5 wt% and usu-ally exceeds 99%.

Economics:Utilities, (per bbl feed) Naphtha DieselFuel, 103 Btu release 48 59.5Electricity, kWh 0.65 1.60Water, cooling (20°F rise), gal 35 42


Liquidfeed

Hydrogen makeup Recycle compressor

Firedheater

Feed/effluentexchangers

Liquid to stripperLow-pressure

flash

High-pressure

flash

Flash gas to fuel

1

START Makeupcompressor



HydrotreatingApplication: Hydrodesulfurization, hydrodenitrogenation and hydro-genation of petroleum and chemical feedstocks using the Unionfin-ing and MQD Unionfining processes.

Products: Low-sulfur diesel fuel; feed for catalytic reforming, FCCpretreat; upgrading distillates (higher cetane, lower aromatics);desulfurization, denitrogenation and demetallization of vacuum andatmospheric gas oils, coker gas oils and chemical feedstocks.

Description: Feed and hydrogen-rich gas are mixed, heated and con-tacted with regenerable catalyst (1). Reactor effluent is cooled andseparated (2). Hydrogen-rich gas is recycled or used elsewhere. Liq-uid is stripped (3) to remove light components and remaining hydro-gen sulfide, or fractionated for splitting into multiple products.

Operating conditions: Operating conditions depend on feedstockand desired level of impurities removal. Pressures range from 500to 2,000 psi. Temperatures and space velocities are determined byprocess objectives.

Yields:Purpose FCC feed Desulf. Desulf. Desulf.Feed, source VGO + Coker AGO VGO DSLGravity, °API 17.0 25.7 24.3 30.1Boiling range, °F 400/1,000 310/660 700/1,000 350/700Sulfur, wt% 1.37 1.40 2.3 0.7Nitrogen, ppmw 6,050 400 830 660Bromine number — 26 — —Naphtha, vol% 4.8 4.2 2.6 3.3Gravity, °API 45.0 50.0 54.0 60Boiling range, °F 180/400 C4/325 C4/356 C5/325Sulfur, ppmw 50 5 40 5Nitrogen, ppmw 30 1 30 0.5Distillate, vol% 97.2 97.6 98.0 99.4Gravity, °API 24.0 26.9 27.8 35.2Boiling range, °F 400+ 325/660 356+ 325+Sulfur, wt% 0.025 0.05 0.20 0.005H2 consump.,scf/bbl 700 350 290 780

Economics:Investment, $ per bpsd 1,200–2,000Utilities, typical per bbl feed:

Fuel, 103 Btu 40–100Electricity, kWh 0.5–1.5

Installation: Several hundred units installed.

Reference: Baron, K., et al., Ketjen Catalyst Symposium, Am-sterdam, the Netherlands, May 27–30, 1984.

Licensor: UOP LLC.

START

Light components

Product

1

2

3

Makeuphydrogen

Feed



HydrotreatingApplication: RCD Unionfining reduces the sulfur, nitrogen, Con-radson carbon, asphaltene and organometallic contents of heavierresidue-derived feedstocks to allow them to be used as either spec-ification fuel oils or as feedstocks for downstream processing unitssuch as hydrocrackers, fluidized catalytic crackers, resid catalyticcrackers and cokers.

Feed: Feedstocks range from solvent-derived materials to atmo-spheric and vacuum residues.

Description: The process uses a fixed-bed catalytic system that oper-ates at moderate temperatures and moderate to high hydrogen par-tial pressures. Typically, moderate levels of hydrogen are consumed

with minimal production of light gaseous and liquid products. How-ever, adjustments can be made to the unit’s operating conditions,flowscheme configuration or catalysts to increase conversion to dis-tillate and lighter products.

Fresh feed is combined with makeup hydrogen and recycled gas,and then heated by exchange and fired heaters before entering theunit’s reactor section. Simple downflow reactors incorporating agraded bed catalyst system designed to accomplish the desired reac-tions while minimizing side reactions and pressure drop buildup areused. Reactor effluent flows to a series of separators to recover recy-cle gas and liquid products. The hydrogen-rich recycle gas is scrubbedto remove H2S and recycled to the reactors while finished productsare recovered in the fractionation section. Fractionation facilities maybe designed to simply recover a full-boiling range product or torecover individual fractions of the hydrotreated product.

Economics:Investment (basis: 15,000 to 20,000 bpsd, 2nd quarter 2000, U.S.

Gulf Coast)$ per bpsd 2,000–3,500

Utilities, typical per barrel of fresh feed (20,000 bpsd basis)Fuel 46 MMBtu/hrElectricity 5,100 kWhSteam 8,900 lb/hr (HP)

1,500 lb/hr (LP)

Installation: Twenty-five licensed units with a combined licensedcapacity of approximately 830,000 bpsd. Commercial applicationshave included processing of atmospheric and vacuum residues andsolvent-derived feedstocks.

Reference: Thompson, G. J., “UOP RCD Unionfining Process,”Robert A. Meyers, ed., Handbook of Petroleum Refining Processes, 2nded., New York, McGraw-Hill, 1996.

Licensor: UOP LLC.

Cold highpress. sep.

START

Residcharge

Guardreactor

HHPS

GasFuel gas Naphtha

Distillate

Treatedatm. resid

Main reactors (2-4)

FractionatorHot low

press. flashCold low

press. flashAmine

scrubber

Rich amine

Makeuphydrogen

Lean amine

Recyclegas comp.

Recyclegas heater



Hydrotreating—catalytic dewaxingApplication: A versatile family of MAKFining Premium DistillatesTechnologies (PDT) is used to meet all current and possible futurepremium diesel upgrading requirements. The addition of selectiveparaffin isomerization dewaxing (MIDW) or selective normal paraf-fin hydrocracking (CFI) function to the hydrodesulfurization (HDS)reactor will improve the diesel product cold flow properties for a widerange of waxy distillate feedstocks.

Products: Ultra-low-sulfur distillate is produced with small amountsof lighter products. The MIDW process is more distillate selective thanthe CFI process, resulting in higher yield of distillate. Low-cloud point,

or pour point product quality diesel can be achieved with the CFI andMIDW processes. The MIDW products will be of higher diesel qual-ity than the CFI distillates.

Description: MAKFining technology is offered through the globalhydroprocessing alliance between ExxonMobil Research and Engi-neering, Akzo Nobel Chemicals, Kellogg Brown & Root and FinaResearch S.A.. MAKFining PDT units combine a family of tech-nologies in low-cost-integrated designs to achieve necessary productuplift. The first step for any PDT unit is ultra-deep HDS. When thedistillate product must also meet stringent fluidity specifications,MAKFining can offer either paraffin isomerization dewaxing (MIDW)or selective normal paraffin cracking based dewaxing technologies(CFI). These can be closely integrated with HDS and other functionsto achieve the full upgrading requirements. Isomerization dewaxingis generally a higher cost process, but delivers higher yields and highertotal product quality (density, aromatics and cetane improvement)at the same level of cloud-point reduction. The isomerization dewax-ing process can be a single- or two-stage process, depending on thelevel of heteroatoms in the feed. The selective paraffin hydrocrack-ing process uses a single-stage design. The MAKFining Premium Dis-tillates Technologies are equally applicable to revamp and grassrootsapplications.

Economics: Investment (basis:15,000 to 25,000 bpsd, 1st quarter2000 U.S. Gulf Cost)

Grassroots unit, $ per bpsd 1,000 to 2,000

Installation: Thirty-six distillate upgrading units have applied theMAKFining Premium Distillates Technologies. Eleven of these appli-cations are revamps.

Reference: “MAKFining—Premium Distillates Technology; TheFuture of Distillate Upgrading,” Paper AM-00-18, NPRA AnnualMeeting, March 2000, San Antonio.

Licensor: Akzo Nobel and ExxonMobil Research & Engineering Co.

Distillatefeed

Steam

Naphtha

Hot s

epar

ator


pump

Absorber

Lean amineFuelgas

Rich amine

Low-sulfurdiesel

Hydrogen

Water wash

Sour water

CFI/MIDWreactor

Makeupcompressor

Coldseparator

Recyclecompressor

Heater



Hydrotreating—HDArApplication: A versatile family of MAKFining Premium DistillatesTechnologies (PDT) is used to meet all current and possible futurepremium diesel upgrading requirements. When feedstock aromaticsare very high, or very low aromatics (<10 wt%) in the product aredesired, a second-stage hydrodearomatization (HDAr) system canreduce costs and avoid very high-design pressures, which wouldotherwise be required for a single-step-base-metal hydrotreatingcatalyst system.

Products: Very high volume yield of ultra-low-sulfur distillate is pro-duced with very low polynuclear and total aromatics content. Cetaneand density improvements of the diesel product can be achieved,depending on the feed quality and processing objectives.

Description: MAKFining technology is offered through the globalhydroprocessing alliance between ExxonMobil Research and Engi-neering, Akzo Nobel Chemicals, Kellogg Brown & Root and FinaResearch S.A. MAKFining PDT units combine a family of technolo-gies in low-cost integrated designs to achieve necessary productuplift. The first step for any PDT unit is ultra-deep hydrodesulfur-ization (UDHDS). Fresh feed and combined recycle and makeupgas are preheated and contact the HDS catalyst in a downflow-con-current-fixed-bed reactor. Effluent from the HDS reactor is hotstripped, and liquid is processed in a small second-stage HDAr sys-tem to reduce polyaromatics or total aromatics to any low leveldesired. The gas fraction is flashed in a cold high-pressure separa-tor. The hydrogen-rich gas is treated in an amine absorber tower toremove H2S and used in the second stage HDAr reactor. The per-formance and size of both stages are optimized to minimize capitalcost. In the above example, a stream stripper is used for final prod-uct recovery. The MAKFining Spider Vortex quench and redistribu-tion technology is key to reducing reactor volume and enhancing theunit’s operability and reliability. The MAKFining Premium Distil-lates Technologies are equally applicable to revamp and grassrootsapplications.


Grassroots unit, $ per bpsd 1,000 to 2,000


Reference: "MAKFining—Premium Distillates Technology: TheFuture of Distillate Upgrading," Paper AM-00-18, NPRA AnnualMeeting, March 2000, San Antonio.


Distillatefeed

Steam

Naphtha

Interstagestripper

Productstripper

Recyclecompressor

Absorber Lean amine Fuelgas

Richamine

Low-aromaticsdiesel

Hydrogen

Water wash

Sour water

UDHDSspidervortexreactor

HDArspidervortexreactor

Makeupcompressor

Heater



Hydrotreating—HDHDC Application: A versatile family of MAKFining Premium DistillatesTechnologies (PDT) is used to meet all current and possible future pre-mium diesel upgrading requirements. The addition of heavy-dieselhydrocracking (HDHDC) function to an hydrodesulfurization (HDS)reactor system will reduce diesel sulfur, nitrogen, ASTM D-86 95% boil-ing point (T95) and polynuclear aromatics, as well as improve diesel prod-uct density and cetane for a wide range of distillate feedstocks.

Products: High volume yield of ultra-low-sulfur distillate is producedalong with some naphtha and fuel gas. The distillate product qual-ity achieved depends on feed and processing objectives, but largereduction in T95, density and polynuclear aromatics—along withimproved cetane—are possible.

Description: MAKFining technology is offered through the globalhydroprocessing alliance between ExxonMobil Research and Engi-neering, Akzo Nobel Chemicals, Kellogg Brown & Root and FinaResearch S.A. MAKFining PDT units combine a family of technolo-gies in low-cost integrated designs to realize necessary productuplift. The first step for any PDT unit is ultra-deep HDS (UDHDS).The addition of heavy diesel hydrocracking (HDHDC) function to theUDHDS unit can achieve T95 boiling point reduction together withhigher levels of density, aromatics reduction, and greater cetaneimprovement. Product quality upgrades are accomplished with con-siderably lower hydrogen consumption in comparison to an aro-matics saturation process. The MAKFining Spider Vortex quench andredistribution technology is key to the implementation of HDHDCin a single-stage process configuration. Feed and combined recycleand makeup gas are preheated and contact the catalyst in a down-flow-concurrent-fixed-bed reactor. The reactor effluent is flashed ina high- and a low-pressure separator. An amine absorber tower is usedto remove H2S from the recycle gas. In the above example, a steamstripper is used for final product recovery. The MAKFining Pre-mium Distillates Technologies are equally applicable to revamp andgrassroots applications.


Grassroots Unit, $ per bpsd 1,100 to 2,000


Reference: "MAKFining—Premium Distillates Technology: TheFuture of Distillate Upgrading," Paper AM-00-18, NPRA AnnualMeeting, March 2000, San Antonio.


Distillatefeed

Steam

Naphtha

Hot s

epar

ator


pump

Absorber

Lean amineFuelgas

Rich amine

Low-aromaticsdiesel

Hydrogen

Water wash

Sour water

HDHDCspidervortexreactor

Makeupcompressor

Heater

Recyclecompressor

Coldseparator



Hydrotreating, residueApplication: Upgrade or convert atmospheric and vacuum residuesusing the Hyvahl process.

Products: Low-sulfur fuels—0.3% to 1.0% sulfur—and RFCC feeds(removal of metals, sulfur and nitrogen, reduction of carbon residue).30% to 50% conversion of the 550°C+ fraction into distillates.

Description: Residue feed and hydrogen, heated in a feed/effluentexchangers and furnace, enter a reactor section typically comprisingguard reactor section, main HDM and HDS reactors.

The guard reactors are onstream at the same time in series andprotect the downstream reactors by removing or converting sediment,metals and asphaltenes. For heavy feeds, they are permutable in oper-ation (PRS technology) and allow catalyst reloading during the run.Permutation frequency is adjusted according to feed metals con-tent and process objectives. Regular catalyst changeout allows highand constant protection of downstream reactors.

Following the guard reactors, the main HDM reactors carry out theremaining demetallization and conversion functions. With most ofthe contaminants removed, the residue is sent to the HDS reactorswhere the sulfur level is reduced to the design specification.

Yields: Typical HDS and HDM rates are above 90%. Net productionof 12% to 25% of diesel + naphtha.

Economics:Investments (basis: 40,000-bpsd VR, 1999 Gulf Coast)

U.S. $ per bpsd 4,500–5,500Utilities (per bbl feed)

Fuel, Gcal 3Power, kWhr 10MP steam production, kg 25HP steam consumption, kg 10Water, cooling, m3 1.1

Installation: A 20,000-tpy plant at Solaize, France. Two units arein operation (one on atmospheric residue feed, the other on vacuumresidue), with a total capacity of 80,000 bpsd.

Reference: “Maintaining On-spec Products with Residue Hydropro-cessing,” NPRA Annual Meeting, March 26–28, 2000, San Antonio.

Licensor: IFP.

START

Feed

Hydrogen

HDM demetallization, conversion

Permutable guardreactors

HDS desulfurization, refining

To fractionationsection

To gastreatment1

a1b 2 543



Iso-octaneApplication: Conversion of isobutylene contained in mixed-C4feeds to iso-octane (2,2,4 tri-methyl pentane) to produce a high-qual-ity gasoline blendstock. The full range of MTBE plant feeds can beprocessed—from refinery FCC, olefin-plant raffinate and isobu-tane dehydrogenation processes. The NExOCTANE process is specif-ically developed to minimize conversion costs of existing MTBEunits and offers a cost-effective alternative to MTBE production.

Products: Iso-octene and iso-octane can be produced, depending onthe refiner’s gasoline pool. Typical product properties are:

Iso-octene Iso-octaneRONC 101–103 99–100MONC 85–87 96–99Specific gravity 0.701–0.704 0.726–0.729Vapor pressure, psia 1.8 1.8ASTM EP, °F 380–390 370–380

Description: In the NExOCTANE process, reuse of existing equipmentfrom the MTBE unit is maximized. The process consists of three sec-tions. First, isobutylene is dimerized to iso-octene in the reaction sec-tion. The dimerization reaction occurs in the liquid phase over anacidic ion-exchange resin catalyst, and it uses simple liquid-phase-fixed-bed reactors. The iso-octene product is recovered in a distillation sys-tem, for which generally the existing fractionation equipment can bereused. The recovered iso-octene product can be further hydrogenatedto produce iso-octane. A highly efficient trickle-bed hydrogenationtechnology is offered with the NExOCTANE process. This compact andcost-effective technology does not require recirculation of hydrogen. Inthe refinery, the NExOCTANE process fits as a replacement to MTBEproduction, thus associated refinery operations are mostly unaffected.

Economics: Investment cost for revamps depend on the existingMTBE plant design, capacity and feedstock composition. Typicalutility requirements per bbl product:

Steam, 150-psig, lb 700Electricity, kWh 2.3Water, cooling, ft3 1.2

Installations: Currently, several licenses for this emerging technologyhave been signed and are under design. The first commercial oper-ation is anticipated for startup in the first half of 2001.

Licensor: Kellogg Brown & Root, Inc., and Neste Engineering Oy(Fortum Group).

TBA recycle

Hydrogen

Isobutylenedimerization

HydrogenationIso-octane

Iso-octeneIso-octeneproduct recovery

C4 feed/isobutylene

C4 raffinate toalky or dehydro



Iso-octane/ iso-octeneApplication: Manufacture of high-octane, low-vapor pressure,“MTBE-free” iso-octene and/or iso-octane for gasoline blending.Coproduction of MTBE and iso-octene/iso-octane can be produced inthe desired ratio.

Feed: Hydrocarbon streams containing reactive tertiary olefinssuch as: FCC C4s, steam-cracker C4s or isobutane dehydrogenationproduct.

Products: Iso-octene or iso-octane stream containing at least 85%of C8s, with less than 5,000 ppm oligomers higher than C12s.

Description: Depending on conversion and investment require-ments, various options are available. A typical one-stage reaction pro-cess, which can provide isobutylene conversion of up to 85%, is as fol-lows. The C4 feed is mixed with a recycle stream containingoxygenates (such as TBA and MTBE), used as “selectivator” andheated before entering the reactor. The reactor (1) is a water-cooled-tubular reactor (WCTR) (or, if available, a boiling-point reactorcould be used for lower conversion requirements in a revamp). Theheat of reaction is removed by circulating water through the shell ofthe WCTR. There is no product recycle. The reactor effluent flows,along with the selectivator, to the debutanizer (2), where iso-octeneis separated from the unreacted C4s. Unreacted C4s are taken as col-umn overhead, while iso-octene, TBA and MTBE are removed as thebottom product together with C5 hydrocarbons, if any. The subsequentbottom product is fed to the iso-octene purification column (3). Thebottom product is iso-octene. It can be sent to storage or fed to the“hydrogenation unit” to produce saturated hydrocarbon—iso-octane.

A two-stage reaction process can also be designed, which allows forconversion up to 99%. In this case, a second reaction stage is pro-vided either as a fixed-bed or catalytic distillation (CD) system.

Economics: Investment (basis grassroots iso-octene unit, charging FCC C4s)

5,000–7,000 U.S. $ per bpsdInvestment for retrofitting an existing MTBE unit to iso-octeneproduction

2,000– 2,500 U.S. $ per bpsdUtilities, per bbl of iso-octene:

Steam, 103 lb 0.2–0.3Water, cooling, gal 1,500–2,000Power, kWh 0.6–1.0

Licensors: Snamprogetti SpA and CDTECH.

Makeupmethanol

Makeup waterIso-octane

product

Iso-octene product

C4 raffinate

C4 feed

Hydrogen

MeOH recovery

Hydrogenation

Selectivator recycle

1 2 3



IsomerizationApplication: To efficiently upgrade the octane number of C5 /C6refinery streams by conversion of normal paraffins to their higheroctane isomers. Typical feedstocks include light straight-run naph-tha, light reformate and light hydrocrackate. In addition to paraffinisomerization, the technology also achieves benzene saturation withsubsequent octane upgrading of resulting cyclohexane.

Products: The Lummus C5 /C6 isomerization process typically pro-

duces a stabilized isomerate with an 84 to 85 RONC. Correspondingyield is in excess of 99.5 vol% on feed. Optionally to achieve higherproduct octane, optimized separation/recycle facilities are incorpo-rated into the process. In one such configuration, a deisohexanizeris used to produce 88 RONC isomerate.

Description: The Lummus process uses Akzo Nobel’s high-activitychlorided-alumina catalyst that allows operation at low temperatures,which maximizes conversion and selectivity while minimizing cat-alyst requirements. Excellent stability at low hydrogen flowrates elim-inates the need for hydrogen recycle compression, further reducinginvestment cost.

As depicted above, the C5/C6 feed and makeup hydrogen streamsare dried over molecular sieves (1), combined, heated to reaction tem-perature in feed/effluent exchangers followed by a trim heater andsent to the fixed-bed reaction zone (2). Reactor product, whichapproaches equilibrium conversion levels, is directed to the productstabilizer (3). Stabilizer overhead, containing light hydrocarbonsand excess hydrogen, is directed to fuel gas via a caustic scrubber (4).Stabilized bottoms is sent to isomerate product storage in single passoperation or optionally to separation facilities in recycle operation.

Economics:Investment estimated (basis ISBL, U.S. Gulf Coast 2000)$/bpsd (typical) 700–1,500

Installation: Three units have been licensed and designed. Approx-imately a dozen of these units use the Akzo Nobel catalyst.

Licensor: ABB Lummus Global Inc. and Akzo Nobel Chemicals b.v.

1 1 2 3 4

Dryers Reactor Stabilizer Scrubber

Fuel gas

Circulatingcaustic

Spent caustic

C5/C6 isomerateC5/C6 feed

Makeuphydrogen

START



IsomerizationApplication: Convert normal olefins to iso-olefins.

Description: C4 olefin skeletal isomerization (IsomPlus)

A zeolite-based catalyst especially developed for this process pro-vides near equilibrium conversion of normal butenes to isobutylene athigh selectivity and long process cycle times. A simple process schemeand moderate process conditions result in low capital and operatingcosts. Hydrocarbon feed containing n-butenes, such as C4 raffinate, canbe processed without steam or other diluents, nor the addition of cat-alyst activation agents to promote the reaction. Near-equilibriumconversion levels up to 44% of the contained n-butenes are achievedat greater than 90% selectivity to isobutylene. During the processcycle, coke gradually builds up on the catalyst, reducing the isomer-

ization activity. At the end of the process cycle, the feed is switched toa fresh catalyst bed, and the spent catalyst bed is regenerated by oxi-dizing the coke with an air/nitrogen mixture. The butene isomerate issuitable for making high purity isobutylene product.

C5 olefin skeletal isomerization (IsomPlus)A zeolite-based catalyst especially developed for this process pro-

vides near-equilibrium conversion of normal pentenes to isoamyleneat high selectivity and long process cycle times. Hydrocarbon feedscontaining n-pentenes, such as C5 raffinate, are processed in theskeletal isomerization reactor without steam or other diluents, northe addition of catalyst activation agents to promote the reaction.Near-equilibrium conversion levels up to 72% of the contained normalpentenes are observed at greater than 95% selectivity to isoamylenes.

Economics: The Lyondell isomerization process offers the advan-tages of low capital investment and operating costs coupled with ahigh yield of isobutylene. Also, the small quantity of heavy byprod-ucts formed can easily be blended into the gasoline pool. Capital costs(equipment, labor and detailed engineering) for three different plantsizes are:

Total installed cost: Feedrate, Mbpd ISBL cost, $MM10 815 1130 30

Utility costs: per barrel of feed (assuming an electric-motor-driven compressor) are:

Power, kWh 3.2Fuel gas, MMBtu 0.44Steam, MP, MMBtu 0.002Water, cooling, MMBtu 0.051Nitrogen, scf 57–250

Installation: One plant is in operation. Three licensed units are invarious stages of design.

Licensor: CDTECH and Lyondell Chemical Co.

34

2

5

MTBE unit raffinate

C4s to MTBE unit

C5+



IsomerizationApplication: Hydrisom is Phillips Petroleum Co.’s selective diolefinhydrogenation process, with specific isomerization of butene-1 tobutene-2 and 3-methyl-butene-1 to 2-methyl-butene-1 and 2-methyl-butene-2. The Hydrisom process uses a liquid-phase reaction over acommercially available catalyst in a fixed-bed reactor.

Description: The Hydrisom process is a once-through reaction and,

for typical cat cracker streams, requires no recycle or cooling. Hydro-gen is added downstream of the olefin feed pump on ratio control andthe feed mixture is preheated by exchange with the fractionatorbottoms and/or low-pressure steam. The feed then flows downwardover a fixed bed of commercial catalyst.

The reaction is liquid-phase, at a pressure just above the bubblepoint of the hydrocarbon/hydrogen mixture. The rise in reactor tem-perature is a function of the quantity of butadiene in the feed andthe amount of butene saturation that occurs.

The Hydrisom process can also be configured using a proprietarycatalyst to upgrade streams containing diolefins up to 50% or more,e.g., steam cracker C4 steams, producing olefin-rich streams for useas chemical, etherification and/or alkylation feedstocks.

Installation of a Phillips Hydrisom unit upstream of an etherifi-cation and/or alkylation unit can result in a very quick payout of theinvestment due to:

• Improved etherification unit operations• Increased ether production• Increased alkylate octane number• Increased alkylate yield• Reduced chemical and HF acid costs• Reduced ASO handling• Reduced alkylation unit utilities• Upgraded steam cracker or other high diolefin streams (30% to

50%) for further processing.

Installation: Ten units licensed worldwide, including an installationat Phillips Refinery, Sweeny, Texas.


Hydrogen

Olefin

Olefinfeed pump

Reactorfeed

heater

Reactor

HF alkylation or etherification unit feed

Reboiler

Reflux pump

Drain

VentLight-endsseparator Overhead

condenser

START



IsomerizationApplication: C5/C6 paraffin-rich hydrocarbon streams are isomer-ized to produce high RON and MON product suitable for addition tothe gasoline pool.

Description: Several variations of the C5/C6 isomerization process areavailable. With either a zeolite or chlorinated alumina catalyst, thechoice can be a once-through reaction for an inexpensive-but-limitedoctane boost, or, for substantial octane improvement, the Ipsorb Isomscheme shown above to recycle the normal paraffins for their completeconversion. The Hexorb Isom configuration achieves a complete nor-mal paraffin conversion plus substantial conversion of low (75) octanemethyl pentanes gives the maximum octane results. The productoctanes from five process schemes for treating a light naphtha feed (70RON) containing a 50/50 mixture of C5/C6 paraffins are:

ChlorinatedZeolite alumina

Process configuration catalyst catalystOnce-through 80 83Deisopentanizer and once-through 82 84Deisohexanizer and recycle 86 88Normal recycle-Ipsorb 88 90Normal and deisohex. recycle-Hexorb 92 92

Operating conditions: The Ipsorb Isom process uses a deisopen-tanizer (1) to separate the isopentane from the reactor feed. A smallamount of hydrogen is also added to reactor (2) feed. The isomerizationreaction proceeds at moderate temperature producing an equilibriummixture of normal and isoparaffins. The catalyst has a long servicelife owing to its regenerability. The reactor products are separatedinto isomerate product and normal paraffins in the Ipsorb molecu-lar sieve separation section (3) which features a novel vapor phasePSA technique. This enables the product to consist entirely ofbranched isomers.

Economics: (basis: Ipsorb “A” Isomerization unit with a 5,000-bpsd70 RONC feed needing a 20 point octane boost):

Investment*, million U.S.$ 13Utilities:HP steam, tph 1.0MP steam, tph 8.5LP steam, tph 6.8Power, kWh/h 310Cooling water, m3/h 100

* Mid-2000, Gulf coast, excluding cost of noble metals

Installation: Of 21 licenses issued for C5/C6 isomerization plants,10 units are operating including one Ibsorb unit.

Licensor: IFP.

C5/C6 feed

Hydrogen

Off gas

Isomerate

Recycle

CW

START

2 31



IsomerizationApplication: To upgrade the octane number of refinery streams richin C5/C6 normal paraffins, such as light-straight run (LSR) naph-tha, light hydrocrackate, raffinate from aromatics extraction and nat-ural gas condensate. Feedstocks may contain up to 100-ppm sulfuron continuous basis and up to 200-ppm-sulfur for short periods of time.

Products: The CKS ISOM process provides an upgrade of 10 to 18octane numbers, depending on the feed and product recovery flowscheme. The flow scheme is tailored to achieve the refiner’s requiredoctane improvement at minimum capital investment and operating cost.

Description: The CKS ISOM process is based on Süd Chemie’sHYSOPAR catalyst, which is sulfur and water tolerant and fullyregenerable. Feed hydrotreating and drying (unless free water is pre-sent) are not required. Less expensive regenerable caustic scrubbingcan be used for feed sulfur levels above 100 ppm. In the once-through configuration depicted above, the C5/C6 feed and makeuphydrogen are heated against reactor effluent and in a feed preheaterand then fed to the reactor. The reactor product, at near-equilibriumconversion level, is fed to a stabilizer. The stabilizer overhead, con-taining excess hydrogen, is compressed and recycled to the reactor.The stabilizer bottoms are sent to a debutanizer where the C4̄overhead goes to fuel gas and bottoms are sent to the gasolineblending pool. For greater octane uplift, the bottoms can be sepa-rated to recycle unconverted n-pentane, n-hexane and methyl pen-tanes to reactor.

Economics: Indicative capital cost for once-through unit (basisISBL, U.S. Gulf Coast) $/bpsd: 500–700

Installation: One isomerization unit is in commercial operation.HYSOPAR catalyst is in service in 12 other units worldwide.


Isomerizationreactor

Isomerateproduct

C4 to fuel gas-

Feed heaterDebutanizer

Reactoreffluentseparator

Naphthafeed

Makeuphydrogen Recycle hydrogen

Recyclegascompressor



IsomerizationApplication: Paraffin isomerization technology for light naphthaoffers a wide variety of processing options that allow refiners to tai-lor performance to their specific needs. Applications include octaneenhancement and benzene reduction. The Penex process is specifi-cally designed for continuous catalytic isomerization of pentanes, hex-anes and mixtures of the two. The reactions take place in a hydro-gen atmosphere, over a fixed catalyst bed, and at operating conditionsthat promote isomerization and minimize hydrocracking.

Products: A typical C5/C6 light naphtha feedstock can be upgraded to82-84 RONC in hydrocarbon once-through operation. This can beincreased to about 87-93 RONC by recycling unconverted normal pen-tane, normal hexane and/or methylpentanes. Some systems for sepa-rating the components for recycle are: vapor phase adsorptive separa-tion (IsoSiv process), liquid phase adsorptive separation (Molex process),

fractionation in a deisohexanizer column or a combination of fraction-ation and selective adsorption. The Par-Isom process is a lower cost iso-merization option. It provides a 1–2 lower octane-number productwith regenerable catalyst. Dryers are not required, recycle hydrogenis needed. The metal oxide catalyst is an ideal replacement for zeoliticcatalyst. This process is a cost-effective revamp option.

Description: Hydrogen recycle is not required for the Penex process,and high conversion is achieved at low temperature with negligibleyield loss. A fired heater is not required. The flow diagram representsthe Hydrogen-Once-Through (HOT) Penex process. A two reactor inseries flow configuration is normally used with the total required cat-alyst being equally distributed between the two vessels. This allowsthe catalyst to be fully utilized.

Feed and makeup hydrogen are dried (1) over adsorbent andthen mixed. The mixture is heated against reactor effluent and sentto the reactors (2). Reactor effluent passes directly to the stabilizer(3) after heat exchange. Stabilizer bottoms are sent to gasolineblending in a once-through operation or to separation (adsorption orfractionation) in a recycle operation. The light ends are sent to a caus-tic-scrubber column and then to fuel.

Economics: The typical estimated erected costs for 2Q1998 ISBL, U.S.Gulf Coast for a 10,000 bpsd unit are:

Flowscheme EEC, $MMPenex 8.5Penex/Molex 23.4Penex/DIH 15.5

Installation: UOP is the world’s leading licensor in C5/C6 isomer-ization technology. The first Penex unit was placed on stream in 1958.Over 180 UOP C5/C6 isomerization units have been commissioned asof June 2000. Another 27 units are in various stages of design andconstruction.

Reference: Hydrocarbon Technology International, 1991, p. 73.

Licensor: UOP LLC

STARTPenex isomerate

Makeup hydrogen Gas to scrubbingand fuel

C5/C6 charge

2 2

3

1

1



Lube hydroprocessingApplication: The Hybrid base oil manufacturing process is an opti-mized combination of solvent extraction and one-stage hydropro-cessing. It is particularly suited to the revamping/debottlenecking ofexisting solvent extraction lube oil plants; capacity increases asgreat as 60% can be achieved. Solvent extraction also liensed by Shell.

Feed: Derived from a wider range of crudes than can be used withsolvent extraction. Yields and capacity are less sensitive to feedstockthan when the solvent extraction process is applied.

Description: Two separate upgrading units are used; solvent extrac-tion and one-stage hydroprocessing. Individual waxy distillatestreams are either mildly solvent-extracted and then hydropro-cessed or are solvent extracted at normal severity. Deasphalted oilis either mildly solvent extracted and then hydroprocessed or isonly hydroprocessed. The choice of solvent extraction and hydropro-

cessing depends upon the feedstock and the objectives of debottle-necking (min. capital expenditure or max. capacity increase).

When the Shell process is used to debottleneck a lube oil plant, itis necessary to construct two new unit: a hydrotreating/redistillationunit and an additional dewaxing unit (the existing dewaxing unit usu-ally has insufficient spare capacity). There is normally no need to con-struct additional vacuum distillation/deasphalting/solvent extractionunits. However, some modifications will be required to the existing vac-uum distillation and solvent extraction units.

Yields: Depend upon the grade of base oil and the crude origin of thefeedstock. Shell Hybrid gives a significantly higher yield of base oilcrude and the yield is much less sensitive to feedstock origin thanwith solvent extraction process.

Base oils obtained via the Shell Hybrid process are lighter in colorand have lower Conradson carbon residue contents than their sol-vent extracted counterparts and can more advantageously be usedin a number of special applications. Moreover, the low-sulfur, low-pour-point gas oil byproducts from the hydrotreating unit can haveenhanced value in special markets, while the quantity of low-valuebyproducts (e.g. extracts) is substantially reduced.

Economics: The following table compares the economics of debot-tlenecking a 300 ktpy solvent extraction complex to 500 ktpy withthe economics of a new 200 ktpy solvent extraction complex.

Solvent extraction Hybrid debottlenecking200 ktpy grass-roots (from 300 to 500 ktpy)

Capital charge 36% of total 24-36% of solvex totalFixed costs 20% of total 7-9% of solvex totalVariable costs 8% of total 8% of solvex totalHydrocarbon cost 36% of total 11% of solvex totalTotal 100% of total 50-64% of solvex total

Installation: The process has been commercially applied in Shell’s Gee-long refinery since 1980. Pertamina is applying the Shell Hybridtechnology to debottleneck its Cilacap refinery—the successful startoccurred in the second half of 1998.

Licensor: Shell Global Solutions International B.V

Atmosphericresidue

Vacuumdistillation

Solventextraction

Waxes/LPGTops

Extracts

Asphalt

Deasphalting

DewaxingHydrotreating& redistillation

125 neutral

250 neutral

500 neutral

Bright stock



Lube treatingApplication: MP Refining is a solvent extraction process that uses N-methyl-2-pyrrolidone (NMP) as the solvent to selectively remove theundesirable components of low lubricating oil quality naturally presentin crude oil distillate and residual stocks. The unit produces paraffinicor naphthenic raffinates suitable for further processing into lube basestocks. The process selectively removes aromatics and compounds con-taining heteroatoms (e.g., oxygen, nitrogen, sulfur).

Products: A raffinate that may be dewaxed to produce a high-quality lube base oil, characterized by high viscosity index, good ther-mal and oxidation stability, light color and excellent additive response.The byproduct extracts, being high in aromatic content, can be usedin some cases for carbon black feedstocks, rubber extender oils andother nonlube applications where this feature is desirable.

Description: The distillate or residual feedstock and solvent arecontacted in the extraction tower (1) at controlled temperatures andflowrates required for optimum counter-current, liquid-liquid extrac-tion of the feedstock. The extract stream, containing the bulk of thesolvent, exits the bottom of the extraction tower. It is routed to a recov-ery solvent to remove contained in this stream. Solvent is separatedfrom the extract oil by multiple-effect evaporation (2) at various pres-sures, followed by vacuum flashing and steam stripping (3) under vac-uum. The raffinate stream exits the overhead of the extraction towerand is routed to a recovery section for removal of the NMP solvent con-tained in this stream by vacuum flashing and steam stripping (4) undervacuum.

Overhead vapors from the steam strippers are condensed andcombined with solvent condensate from the recovery sections and aredistilled at low pressure to remove water from the solvent (5). Sol-vent is recovered in a single tower because NMP does not form anazeotrope with water. The water is drained to the oily-water sewer.The solvent is cooled and recycled to the extraction section.

Economics:

Investment: (basis 10,000 bpsd, 2000 U.S. Gulf Coast) $ per bpsd 2,500

Utilities, typical per bbl feed:

Fuel, absorbed, 103 Btu 130Electricity, kWh 0.8Steam, barrels 8.1Water, cooling (25°F), gal 550

Installation: This process has been used in 13 licensed units to pro-duce high-quality lubricating oils. Presently, two new units thatwill refine used oil are in the design stage. Of this number, eight areunits converted from phenol or furfural, with another two unitsbeing planned for conversion from phenol.

Licensor : Bechtel Corp

START

Extract

Refined oil

WaterStm.

Stm.

Feed

1 5

432



Lube treatingApplication: Lube raffinates from extraction are dewaxed to pro-vide basestocks having low pour points (as low as –35°C). Basestocksrange from light stocks (60N) to higher viscosity grades (600N andBright Stock). Byproduct waxes can also be upgraded for use infood applications.

Feeds: DILCHILL dewaxing can be used for a wide range of stocksthat boil above 550°F, from 60N up through Bright Stock. In addi-tion to raffinates from extraction, DILCHILL dewaxing can beapplied to hydrocracked stocks and to other stocks from raffinatehydroconversion processes.

Processes: Lube basestocks having low pour points. Althoughslack waxes containing 2–10 vol% residual oil are the typical byprod-

ucts, lower-oil-content waxes can be produced by the use of additionaldewaxing and/or “warm-up deoiling” stages.

Description: DILCHILL is a novel dewaxing technology in whichwax crystals are formed by cooling waxy oil stocks, which have beendiluted with ketone solvents, in a proprietary crystallizer towerthat has a number of mixing stages. This nucleation environment pro-vides crystals that filter more quickly and retain less oil. This tech-nology has the following advantages over conventional incremental-dilution dewaxing in scraped surface exchanges: less filter area isrequired, less washing of the filter cake to achieve the same oil-in-wax content is required, refrigeration duty is lower, and scraped sur-face chillers which means that unit maintenance costs are lower. Nowax recrystallization is required for deoiling.

Warm waxy feed is cooled in prechillers before it enters theDILCHILL crystallizer tower. Cold solvents is then added in thecrystallizer tower under highly agitated conditions. Most of the crys-tallization occurs in the crystallizer tower. The slurry of wax/oil/ketoneis then further cooled in scraped surface chillers and the slurry isthen filtered in rotary vacuum filters. Flashing and stripping of prod-ucts recover solvent. Additional filtration stages can be added torecover additional oil or produce low-oil-content waxes.

Economics: Depend on the slate of stocks to be dewaxed, the tar-get pour points and the target oil-in-wax content.

Utilities: Depend on the slate of stocks to be dewaxed, pour pointtargets and the required oil-in-wax content.

Installation: The first application of DILCHILL dewaxing was theconversion of an Exxon affiliate unit on the U.S. Gulf Coast in 1972.Since that time, ten other applications have been constructed. Theseapplications include both grassroots units and conversions of incre-mental dilution plants. Six applications use “warm-up deoiling”.


Deoiling filters(2 stages)

Waxy feed

Cold-washsolvent

Cold-wash solvent

Warm-updeoiling heater

Dewaxing filters1 or 2 stages

Wax slurry

Fresh solventRefrigerationsystem

Solvent Solventrecovery

Solventrecovery

Solventrecovery

“Foots oil”Dewaxed waxDewaxed oil

START

Precoolers

Dichillcrystallizer(s)

Scrapedsurfacechillers



Lube treatingApplication: Unconverted oil from a fuels hydrocracker is used toproduce higher quality lube base stocks at lower investment and oper-ating costs than either solvent refining or lube oil hydrocracking uti-lizing the Yukong UCO Lube Process.

Description: The oils manufactured by the Yukong UCO Lube Pro-cess have many desirable properties as lube base stocks over thoseproduced by conventional solvent-refining or lube hydrocrackingprocesses.

Unconverted oil from the existing fractionator in a fuels hydroc-racker is processed and separated into grades having the desired vis-cosity, which are then cooled and sent to intermediate storage. Thevarious grades of base oil are then catalytically dewaxed in blocked

operation. Excess distillates are sent back to the hydrocracker.

Since the withdrawn UCO can usually be replaced with an equalamount of additional fresh vacuum distillate feed, the hydrocrackerfuels production is maintained. The hydrocracking and catalyticdewaxing steps are not included in the Yukong UCO Lube Process,but are readily available from others.

Properties:Yukong

Solvent Lube UCO LubeTest item Test method refining hydrocracking Process

Viscosity @ 100°C, cSt ASTM D 445 5.2 5.1 6.0Viscosity index ASTM D 2270 97 99 130Pour point, °C ASTM D 97 -12 -12 -12CCS vis @ -20°C, cP ASTM D 2602 2,100 2,000 1,440Flash point, °C ASTM D 92 218 220 234NOACK volatility, wt% DIN 51581 17.0 16.6 7.8Aromatics, wt% ASTM D 2549 27.7 3.5 1.0Sulfur content, wt% ANTEC 0.58 0.03 0.00

Economics: Investment (Basis: 5,000 bpd of lube base oils exclud-ing fuels hydrocracker, 1998 U.S. Gulf Coast) $80 million.

Installations: 3,500 bpd of VHVI lube base oils at SK Corporation’sUlsan refinery.

References: Andre, J. P., S. H. Kwong and S. K. Hahn, “Yukong’snew lube base oil plant,” Hydrocarbon Engineering, November 1997.

“An economical route to high quality lubricants,” Am-96-38, NPRA.

Licensor: Washington Group International, Petroleum andChemicals Technology Center, under exclusive arrangement withSK Corporation.

STARTUnconverted oil (UCO)

Distillation

Intermediatestorage

Hydrogen

Catalyticdewaxing

Lubeproducts

Lights torefinery

Excess distillates



NOx abatementApplication: Flue gases are treated with ammonia via ExxonMo-bil’s proprietary selective noncatalytic NOx reduction technology—Thermal DeNOx. NOx plus ammonia (NH3) are converted to ele-mental nitrogen and water if temperature and residence time areappropriate. The technology has been widely applied since it was firstcommercialized in 1974.

Products: If conditions are appropriate, the flue gas is treated toachieve NOx reductions of 40% to 70%+ with minimal NH3 slip or

leakage.

Description: The technology involves the gas-phase reaction of NOwith NH3 (either aqueous or anhydrous) to produce elemental nitro-gen if conditions are favorable. Ammonia is injected into the flue gasusing steam or air as a carrier gas into a zone where the temperatureis 1,600°F to 2,000°F. This range can be extended down to 1,300°F witha small amount of hydrogen added to the injected gas. For mostapplications, wall injectors are used for simplicity of operation.

Yield: Cleaned flue gas with 40% to 70%+ NOx reduction and lessthan 10-ppm NH3 slip.

Economics: Considerably less costly than catalytic systems but rel-atively variable depending on scale and site specifics. Third-partystudies have estimated the all-in cost at about 600 U.S.$/ton of NOxremoved.

Installation: Over 135 applications on all types of fired heaters, boil-ers and incinerators with a wide variety of fuels (gas, oil, coal, coke,wood and waste).

Reference: McIntyre, A. D., “Applications of the THERMAL DeNOxprocess to utility and independent power production boilers,” ASMEJoint International Power Generation Conference, Phoenix, 1994.

McIntyre, A. D., “The THERMAL DeNOx process: Liquid fuelsapplications,” International Flame Research Foundation’s 11th TopicOriented Technical Meeting, Biarritz, France, 1995.

McIntyre, A. D., “Applications of the THERMAL DeNOx processto FBC boilers,” CIBO 13th Annual Fluidized Bed Conference, LakeCharles, Louisiana, 1997.


Combustion airFuel

Injectors

NOxanalyzerNH3 flow

controller

NH3vaporizer

Anhydrous NH3storage

Pressurecontroller

Flow controller

Heater load

Heater

Heater load

Carrier supply



Oily waste treatmentApplication: Oily sludges/emulsions are treated with microwaveenergy to preferentially heat the water and destabilize the emulsion.Microwave separation technology (MST) enables more rapid sepa-ration of the emulsion into its three constituent phases via cen-trifuging or gravity separation.

Products: Destabilized emulsion that can typically be separated intoan oil-rich phase (1% to 5% BS&W), a water-rich phase (1% to 2%

oil plus solids) and a solids stream. MST is most readily applied tosludges/emulsions that are less than 5% to 10% solids and have anoil-to-water ratio between 4 to 1 and 1 to 4.

Description: Sludge is fed from a holding tank at a temperature of80°F to 150°F. Radio frequency microwave energy is applied to the emul-sion to preferentially heat the water, facilitating separation by creat-ing differences in surface tension and viscosity of the constituentphases. The destabilized emulsion typically exits the unit at a tem-perature between 180°F and 200°F. The emulsion can then be sepa-rated via centrifuging or gravity separation. Typically, the oil is recov-ered and further processed, the water is sent to wastewater treatmentand the solids are treated further or landfilled. Single units can bedesigned for up to 4,000 bpd of feed. Higher rates can be handled byplacing several units in parallel. The units are compact and can be skidor trailer mounted. They are simple to operate (with remote monitoringand checking during operator rounds) and require low maintenance.

Economics: MST units are typically leased at fees of 1 to 2 U.S.$/bblof sludge treated. Leasee pays for site prep and utilities. The majorutility is electric power and is less than 100 watts/bpd of sludge.

Installation: MST is in commercial operation at ExxonMobil’s Tor-rance, California, refinery.

Reference: Albinson, K. R., C. H. Hsai, T. R. Melli, and G. L. Wool-ery, “Microwave Separation Technology (MST),” AIChE Spring Meet-ing, Atlanta, 2000.

Licensor: Imperial Petroleum Recovery Corp./ExxonMobil Research& Engineering Co.

Incomingemulsion

Settling tank 2

CentrifugeEither

Settling tank2

SolidsWaterOil

SolidsWaterOil

SolidsWaterOil

Settling tank1

PumpsAutotuner

Emulsionreceiving tank

Microwavepower unit

Microwaveapplicator

Wave guide

Emulsion breakingsystem

Emulsion separationsystem



Olefins recoveryApplication: Pro-Quip’s Cryo-Plus process recovers propylene andheavier components from refinery offgas streams. Typical applica-tions are on cat crackers, cokers or reformers downstream of the exist-ing gas-recovery systems. Incremental valuable hydrocarbons thatare currently being lost to the refinery fuel system can now be eco-nomically recovered.

Description: Refinery offgases from cat crackers, cokers or other

sources are first dehydrated by molecular sieve (1). The expander/com-pressor (2a) compresses the gas stream, which is then cooled byheat exchange with internal process streams (3). Depending on therichness of the feed gas, supplemental refrigeration (4) may be usedto further cool the gas stream prior to primary vapor/liquid separa-tion (5). Light gases are fed to a turboexpander (2b) where the pres-sure is reduced resulting in a low discharge temperature. Theexpander discharge is fed to the bottom of the LEFC (6). The HEFC(7) overhead is cooled and fed to the top of the LEFC. The recoveredpropylene and heavier liquid stream exit the bottom of the HEFC (7).Process advantages include:

• Low capital cost• High propylene recovery (up to 99%)• Low energy usage• Small footprint—can be modularized• Simple to operate• Wide range of turndown capability.

Economics: Typically, the payback time for plant investment is oneto two years.

Installation: Sixteen plants operating in U.S. refineries, with twounder construction. The first plant was installed in 1984.

References: Buck, L., “Separating Hydrocarbon Gases,” U.S. PatentNo. 4,617,039, Oct. 14, 1986.

Key, R., and Z. Malik, “Technology advances improve liquid recov-ery from refinery offgases,” NPRA Annual Meeting, San Antonio,paper AM-00-06, March 26–28, 2000.

Licensor: Pro-Quip Corp, a subsidiary of Linde A.G.

C3

C3Inlet heatexchanger

Inlet gasfromdehydration

Residue gasto fuel

Expander

Expandercompressor

LEFCCondensate

Liquid product

Stm.

HEFC

Coldseparator

56 7

3

2a

2b

1



Resid catalytic crackingApplication: Selective conversion of gas oil and heavy residualfeedstocks.

Products: High-octane gasoline, distillate and C3–C4 olefins.

Description: Catalytic and selective cracking occurs in a short-con-tact-time riser (1) where oil feed is effectively dispersed and vaporizedthrough a proprietary feed injection system. Operation is carried outat a temperature consistent with targeted yields. Reaction productsexit the riser-reactor through a high-efficiency, proprietary riser ter-mination device; (2) spent catalyst that has not been cooled is pre-stripped and flows through a rapid preliminary stripping section, fol-lowed by a high-efficiency baffled stripper prior to regeneration.

Only the vapor products are quenched using Amoco’s proprietaryquench technology to give the lowest dry gas and maximum gasoline

yield. The hydrocarbons are further cleaned by cyclones before they aretransferred to fractionation. Regeneration in two stages (3, 4) with pro-prietary air rings and catalyst distribution systems results in very cleancatalyst with a minimum of hydrothermal deactivation, plus superiormetals tolerance relative to single-stage regenerator systems. These ben-efits are derived by operating the first-stage regenerator in a partial-burn mode, the second-stage regenerator in a full combustion mode andboth regenerators in parallel with respect to air and flue gas flows. This,in turn, results in lower air requirements and two smaller regenera-tor vessels compared to one large regenerator vessel.

Maximum production of more desirable products can be achieved withthe proprietary Mixed Temperature Control (MTC) system (5). Heatremoval for heavier feedstocks (above 6 CCR) is accomplished by theuse of a reliable dense-phase catalyst cooler which has been com-mercially proven and is licensed exclusively by Stone & Webster/IFP.

The converter vessels use a cold-wall design that results in minimumcapital investment and maximum mechanical reliability and safety.Cracking operation makes use of advanced fluidization technologycombined with a proprietary reaction system. Unit design is tailoredto refiner’s needs and can include wide turndown flexibility. Availableoptions include power recovery in addition to waste-heat recovery.

Existing gas oil units can be easily retrofitted to this technology.Revamps incorporating proprietary feed injection and riser termi-nation devices and vapor quench result in substantial improve-ments in capacity, yields and feedstock flexibility within the mechan-ical limits of the existing unit.

Installation: Stone & Webster has licensed 26 full-technology unitsand performed more than 100 revamp projects.

Reference: Letzsch, W. S., “Commercial performance of the latestFCC technology advances,” paper AM-00-07, NPRA Annual Meeting,March 2000.

Licensor: Stone & Webster Inc., a Shaw Group Co., and InstitutFrançais du Pétrole

3

4

1

2

Gas oil or resid. feed5

Number 2 flue gas

Riser termination device

Vapor quench

StripperReactor riser

MTC system

Second-stageregenerator

Product vapors

Lift air

Air ring

First-stage regenerator

Number 1 flue gas

Withdrawal well

Air ringReactor

START



Residue hydroprocessingApplication: Produces maximum distillates and low-sulfur fuel oil,or low-sulfur LR-CCU feedstock, with very tight sulfur, vanadium andCCR specifications, using moving bed “bunker” and fixed-bed tech-nologies. Bunker units are available as a retrofit option to existingfixed-bed residue HDS units.

Description: At limited feed metal contents, the process typicallyuses all fixed-bed reactors. With increasing feed metal content, oneor more moving-bed “bunker” reactors are added up-front of thefixed-bed reactors to ensure a fixed-bed catalyst life of at least oneyear. A steady state is developed by continuous catalyst addition andwithdrawal: the catalyst aging is fully compensated by catalystreplacement, at typically 0.5 to 2 vol% of inventory per day.

An all bunker option, which eliminates the need for catalystchange-out, is also available. A hydrocracking reactor, which converts

the synthetic vacuum gasoil into distillates, can be efficiently inte-grated into the unit. A wide range of residue feeds, like atmosphericor vacuum residues and deasphalted oils, can be processed using Shellresidue hydroprocessing technologies.

Operating conditions:Reactor pressures: 100–200 bar

1,450–3,000 psiReactor temperatures: 370–420°C

700–790°F

Yields: Typical yields for an SR HYCON unit on Kuwait feed:SR with

Feedstock (95% 520C+) integrated HCUYields: [%wof] [%wof]Gases C1 – C4 3 5Naphtha C5 – 165°C 4 18Kero + gasoil 165 – 370°C 20 43VGO 370 – 580°C 41 4Residue 580°C+ 29 29H2 cons. 2 3

Economics: Investment costs for the various options depend stronglyon feed properties and process objectives of the residue hydroprocessingunit. Investment costs for a typical new single string 5,000 tpsd SR-Hycon unit will range from 200–300 MM US $, the higher figureincludes an integrated hydrocracker.

Installation: There is one unit with both bunker reactors and fixed-bed reactors, operating on short residue (vacuum residue) at 4,300 tpdor 27 kbpsd capacity, and two all-fixed bed units of 7,700 and 7,000 tpd(48 and 44 kbpsd resp.), the latter one in one single string. Commer-cial experiences range from low-sulfur atmospheric residues to high-metal, high-sulfur vacuum residues with over 300 ppmw metals.

Reference: Scheffer, B., et al, “The Shell Residue HydroconversionProcess: Development and Achievements,” The European RefiningTechnology Conference, London, November 1997.


START Feed

Fresh gas

To fractionator

HLPS

HHPS CHPS

CLPS

Cat. Cat.

Cat. Cat.

HDM section HCON sectionCat.

Quench gas to reactorsCat.



Thermal gasoil processApplication: The Shell Thermal Gasoil process is a combinedresidue and waxy distillate conversion unit. The process is an attrac-tive low-cost conversion option for hydroskimming refineries ingasoil-driven markets or for complex refineries with constrainedwaxy distillate conversion capacity. The typical feedstock is atmo-spheric residue, which eliminates the need for an upstream vacuumflasher. This process features Shell Soaker Visbreaking technologyfor residue conversion and an integrated recycle heater system forthe conversion of waxy distillate.

Description: The preheated atmospheric (or vacuum) residue ischarged to the visbreaker heater (1) and from there to the soaker (2).The conversion takes place in both the heater and soaker and is con-

trolled by the operating temperature and pressure. The soaker efflu-ent is routed to a cyclone (3). The cyclone overheads are charged toan atmospheric fractionator (4) to produce the desired productsincluding a light waxy distillate. The cyclone and fractionator bot-toms are routed to a vacuum flasher (6), where waxy distillate is recov-ered. The combined waxy distillates are fully converted in the dis-tillate heater (5) at elevated pressure.

Yields: Depend on feed type and product specifications.Feed atmospheric residue Middle East

Viscosity, cSt @ 100°C 31Products in % wt. on feed

Gas 6.4Gasoline ECP 165°C 12.9Gasoil ECP 350°C 38.6Residue ECP 520°C+ 42.1

Viscosity 165°C plus, cSt @100°C 7.7

Economics: The investment amounts to 1,400–1,600 U.S.$/bblinstalled excluding treating facilities and depending on capacityand configuration (basis: 1998)

Utilities, typical per bbl @ 180°C:Fuel, Mcal 34Electricity, kWh 0.8Net steam production, kg 29Water, cooling, m3 0.17

Installation: Eight Shell thermal gasoil units have been built andare in operation. Post startup services and technical services onexisting units are available from Shell.

Reference: “Thermal Conversion Technology in Modern PowerIntegrated Refinery Schemes,” 1999 NPRA Annual Meeting.

Licensor: Shell International Oil Products B.V., and ABB LummusGlobal B.V

Charge

Naptha

Gasoil

Waxydistillate

Vacuum flashedcracked residue

Gas

Steam

Steam6

5

4

2

1

3



TreatingApplication: Treating gas, LPGs, butanes, gasolines, kerosines and diesels with caustic, amines, water and acid using FIBER-FILMtechnology.

Description: A proprietary FIBER-FILM Contactor is used in aque-ous treating processes to achieve intimate, co-current contactingbetween the hydrocarbon feed and aqueous solution. The FIBER-FILM Contactor is comprised of a bundle of long, continuous, smalldiameter fibers contained in a cylinder. The aqueous solution coatsthe surface of the fibers while the hydrocarbon stream flows as a con-tinuous phase through the fiber bundle, coming into intimate con-tact with the solution adhering to the fiber surface. The large inter-facial area created by the contactor greatly enhances mass transferwithout dispersion of one phase into the other as is necessary for typ-ical conventional mixing systems. Process advantages include:

• Low capital cost• Small sized equipment and low space requirement• Low pressure drop• Can be retrofitted into existing systems or skid mounted for easy

system installation• Low guaranteed aqueous carryover.AQUAFINING FIBER-FILM Technology uses water to remove

amines and caustic contaminants from hydrocarbon streams.THIOLEX FIBER-FILM Technology removes H2S, COS and mer-

captans from gas, LPGs, butanes and gasolines with caustic.AMINEX FIBER-FILM Technology removes H2S, COS and CO2

from gas, LPGs and butanes with amines.THIOLEX coupled with REGEN Technology, a caustic regeneration

process, is used for mercaptan extraction with minimal caustic con-sumption. One or more stages of caustic extraction are used to removemercaptans from gas, LPGs, butanes and gasolines. The catalyst con-taining caustic solution then is sent to a tower for regeneration withair. The disulfides formed are either gravity separated and/or solventextracted. The regenerated solution is then reused in the extraction unit.

MERICAT FIBER-FILM Technology uses a catalyst-containingcaustic solution and air to oxidize mercaptans to disulfides ingasolines.

MERICAT II FIBER-FILM Technology sweetens kerosine/jet fuelby combining Mericat with a catalyst impregnated carbon bed.

NAPFINING FIBER-FILM Technology uses caustic to reduce theacidity of kerosines/jet fuel and heavier middle distillates.

CHLOREX FIBER-FILM Technology uses dilute caustic to removeHCl and NH4Cl from reformer gas and liquid products.

ESTEREX FIBER-FILM Technology uses sulfuric acid to removeneutral and acidic esters from alkylation reactor effluent streams.

MERICON oxidizes and/or neutralizes spent caustics containingsulfides, mercaptans, naphthenic acids and phenols.

Installation: Approximately 500 installations treating 5.0 millionbpsd and 21 MMscfd in 37 countries.

Licensor: Merichem Co.

Jet fuel

4 5

MM

12

32

Jet fuel

Water in

Water out

Recycle

Caustic out

Re-cycle

Recycle

Catalyst in (batch)Air

Caustic in

START

LC

LCLC



VisbreakingApplication: Manufacture incremental gas and distillate productsand simultaneously reduce fuel oil viscosity and pour point. Also,reduce the amount of cutter stock required to dilute the resid to meetthe fuel oil specifications. Foster Wheeler/UOP offer “coil” type vis-breaking process.

Products: Gas, naphtha, gas oil, visbroken resid (tar).

Description: In a “coil” type operation, charge is fed to the visbreakerheater (1) where it is heated to a high temperature, causing partialvaporization and mild cracking. The heater outlet stream is quenchedwith gas oil or fractionator bottoms to stop the cracking reaction. Thevapor-liquid mixture enters the fractionator (2) to be separated intogas, naphtha, gas oil and visbroken resid (tar).

Operating conditions: Typical ranges are:Heater outlet temperature, °F 850–910Quenched temperature, °F 710–800An increase in heater outlet temperature will result in an increase

in overall severity.

Yields:Feed, source Light Arabian Light ArabianType Atm. resid Vac. residGravity, °API 15.9 7.1Sulfur, wt% 3.0 4.0Concarbon, wt% 8.5 20.3Viscosity, CKS @ 130°F 150 30,000

CKS @ 210°F 25 900Products, wt%Gas 3.1 2.4Naphtha (C5–330°F) 7.9 6.0Gas oil (330–600°F) 14.5 15.5(1)

Visbroken resid (600°F+) 74.5 76.1(2)

(1) 330–662°F cut for Light Arabian vacuum residue(2) 662°F+ cut for Light Arabian vacuum residue

Economics:Investment (basis: 40,000–10,000 bpsd, 4th Q, 1999, U.S. Gulf),$ per bpsd 785–1,650Utilities, typical per bbl feed:Fuel, MMBtu 0.1195Power, kW/bpsd 0.0358MP steam, lb 6.4Water, cooling, gal 71.0

Installation: Over 50 units worldwide.

Reference: Handbook of Petroleum Refining Processes, 2nd Ed.,McGraw-Hill, 1997, pp. 12.83–12.97.

Licensor: Foster Wheeler USA Corp./UOP LLC.

Reducedcrude charge

Gas

Gasoline

Gas oil

Tar

SteamSTART

21



VisbreakingApplication:The Shell Soaker Visbreaking process is most suitableto reduce the viscosity of vacuum (and atmospheric) residues in(semi) complex refineries. The products are primarily distillatesand stable fuel oil. The total fuel oil production is reduced by decreas-ing the quantity of cutter stock required. Optionally, a Shell vacuumflasher may be installed to recover additional gas oil and waxy dis-tillates as cat cracker or hydrocracker feed from the cracked residue.The Shell Soaker Visbreaking technology has also proven to be a verycost-effective revamp option for existing units.

Description: The preheated vacuum residue is charged to the vis-breaker heater (1) and from there to the soaker (2). The conversiontakes place in both the heater and the soaker. The operating tem-perature and pressure are controlled such as to reach the desired con-

version level and/or unit capacity. The cracked feed is then chargedto an atmospheric fractionator (3) to produce the desired products likegas, LPG, naphtha, kerosine, gas oil, waxy distillates and crackedresidue. If a vacuum flasher is installed, additional gas oil and waxydistillates are recovered from the cracked residue.

Yields: Vary with feed type and product specifications.Feed, vacuum residue Middle EastViscosity, cSt @100°C 770Products, wt%Gas 2.3Gasoline, 165°C EP 4.7Gas oil, 350°C EP 14.0Waxy distillate, 520°C EP 20.0Residue, 520°C+ 59.0Viscosity, 165°C plus, cSt @100°C 97

Economics:The investment amounts to 1,000 to 1,400 U.S.$/bbl installed excluding treating facilities and depending on capacity and the presence of a vacuum flasher (basis: 1998).

Utilities, typical consumption per bbl feed @180°C:Fuel, 103 kcal 16Electricity, kWh 0.5Net steam production, kg 18Water, cooling, m3 0.1

Installation: 70 Shell Soaker Visbreakers have been built or are cur-rently under construction. Post startup services and technical ser-vices for existing units are available from Shell.

Reference: Visbreaking Technology, Erdöl und Kohle, January1986.

Licensor: Shell Global Solutions International B.V. and ABB Lum-mus Global B.V.

Residuecharge

Gas

1

Naphtha

Gas oil

Visbroken residue

Vacuum gas oil

Cutter stock

Vacuum system

Steam

4

3

Steam

START

2



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