2017
REFINING
PROCESSES
HANDBOOK
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Premier Sponsors:
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Premier Sponsors:
Sponsor:
Hydrocarbon Processing's 2017 Refining Processes Handbook reflects all of the latest advancements available
in process technologies, catalysts and equipment—an inclusive catalog of established and new refining technologies
that can be applied to existing and grassroots facilities.
Refiners must balance capital investment and operating strategies that will provide optimum profitability for their
organization. Accordingly, refiners apply leading-edge technology in conjunction with “best practices” for refining
fuels and petrochemical feedstocks from crude oil. Economics and regulations drive efforts to conserve energy
consumption, minimize waste, improve product qualities and, most importantly, increase yields and throughput.
For more than 65 years, the HP “Refining Processes Handbook” has been a definitive resource for processing
technologies in the oil refining industry. This well-organized handbook contains single-page summaries about
hundreds of leading-edge licensable refining technologies. Each process page includes a flow diagram, as well
as process type, application feeds and products, descriptions of operating conditions and yields, advantages,
comparative economics, utilities, how a process was developed and is delivered, licensor/supplier contact information,
and websites to access more information.
Processes covered are Alkylation; Aromatics; Biofuels; Catalytic Cracking; Coking; Deasphalting; Desulfurization;
Distillation; Ethers; Hydrocracking; Hydrogen Generation; Hydroprocessing; Isomerization; Lubricants and Waxes;
Olefins; Oxygen Enrichment; Treating Gas/Liquids; and Upgrading Heavy Oil.
The handbook is specifically designed to provide engineers and refining professionals with technical information
that they can quickly reference at any time. Company pages summarize their process technology services. In addition
to this indexed PDF, the handbook includes articles provided by sponsors.
The 2017 Refining Processes Handbook is available on USB card and via our website for paid subscribers.
Additional copies may be ordered from our website.
Photo: View of the continuous catalytic reforming unit in one of Sinopec’s refineries in China. Photo courtesy of
Sinopec Hainan Refining and Chemical Ltd. Co.
Please read the TERMS AND CONDITIONS carefully.
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www.HydrocarbonProcessing.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Premier Sponsors:
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Premier Sponsors:
Process Categories
Sponsor:
Alkylation
Hydrogen Generation
Aromatics
Hydroprocessing
Biofuels
Internals
Catalytic Cracking
Isomerization
Coking
Lubricants and Waxes
Deasphalting
Olefins
Desulfurization
Oxygen Enrichment
Distillation
Treating, Gas/Liquid
Ethers
Upgrading, Heavy Oil
Hydrocracking
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Premier Sponsors:
Company Index
Sponsor:
Air Liquide
GTC Technology
Air Products
Haldor Topsoe
Amec Foster Wheeler
Johnson Matthey
Axens
KBR Inc.
BASF
Linde Engineering North America Inc.
Bechtel Hydrocarbon Technology Solutions Inc.
Merichem Company
CB&I
Saipem S.p.A.
Chevron Lummus Global LLC (CLG)
Shell Global Solutions International B.V.
China Petrochemical Technology Co. Ltd.
Siirtec Nigi S.p.A.
DuPont Clean Technologies
TechnipFMC
Eni S.p.A. Refining & Marketing
thyssenkrupp
ExxonMobil Catalysts and Licensing LLC
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Alkylation
Transfer alkyl group to another molecule to make high-octane
AlkyClean®
CB&I
Convert MTBE units, DIMER8®
CB&I
K-SAAT™
KBR Inc.
Low-temperature acid catalyzed CDAlky®
CB&I
Selectopol™
Axens
STRATCO® Technology
DuPont Clean Technologies
Sulfuric Acid Alkylation technology
ExxonMobil Catalysts and Licensing LLC
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Aromatics
Processes to create/separate mono-cyclic hydrocarbon fuels
AED-BTX
LHAT-M
Dividing wall column in xylenes services
Morphylane® Process
EMHAI process
MTDP-3 process
EMTAM℠ process
Octanizing® and Aromizing™
GT-BenZap®
Olgone℠ process
GT-BTX®
PxMax℠ process
GT-BTX PluS®
S-CCCR
GT-TransAlk℠
SED
LHAT-F
S-TDT
KBR Inc.
ExxonMobil Catalysts and Licensing LLC
ExxonMobil Catalysts and Licensing LLC
ExxonMobil Catalysts and Licensing LLC
GTC Technology
GTC Technology
GTC Technology
GTC Technology
China Petrochemical Technology Co. Ltd
China Petrochemical Technology Co. Ltd
thyssenkrupp
ExxonMobil Catalysts and Licensing LLC
Axens
ExxonMobil Catalysts and Licensing LLC
ExxonMobil Catalysts and Licensing LLC
China Petrochemical Technology Co. Ltd
China Petrochemical Technology Co. Ltd
China Petrochemical Technology Co. Ltd
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Biofuels
Create fuels from arable crops, woody biomass, fats or algae
Biodiesel—FAME
Air Liquide
Green Refinery/Ecofining™
Eni S.p.A. Refining & Marketing
Vegan®
Axens
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Catalytic Cracking
Catalytically convert high-MW fractions to gasoline, olefins
Deep Catalytic Cracking—DCC
Fluidized catalytic cracking
FCC
High Severity—HS-FCC™
TechnipFMC
FCC
BASF
TechnipFMC
Shell Global Solutions International BV
Axens
High Severity HS-FCC™
TechnipFMC
FCC Additive Technology
Indmax℠ FCC for maximum olefins
FCC-MIP
Orthoflow, ATOMAX™
FCC pretreatment
R2R™
FCC Technology Platform Options
Resid R2R™
Fluid catalytic cracking
Resid to Propylene—R2P™
BASF
China Petrochemical Technology Co. Ltd
Haldor Topsoe
BASF
CB&I
Fluid Catalytic Cracking (FCC)
Axens
CB&I
KBR Inc.
Axens
TechnipFMC
Axens
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Coking
Petroleum coke from high-temperature residue processing
Delayed coking
CB&I
Delayed coking
China Petrochemical Technology Co. Ltd
Delayed coking
KBR Inc.
Delayed coking technology
Chevron Lummus Global LLC (CLG)
SYDEC℠
Amec Foster Wheeler
ThruPlus® Delayed Coking
Bechtel Hydrocarbon Technology Solutions Inc.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Deasphalting
Asphalt content reduction, typically by solvent extraction
ROSE®
KBR Inc.
Solvent Deasphalting
Amec Foster Wheeler
Solvent Deasphalting
thyssenkrupp
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization
Includes desulfurizing and sulfur recovery, sulfur processing
Advanced Ammonia Claus
Modified Claus
Amine Treating
SCOT® (Shell Claus Off-gas Treatment)
Ammonia Claus
Shell sulfur degassing
CANSOLV® TGT+
Sour Water Treating
Claus Sulfur Recovery Units
SRU, TGT and Degas
Claus Tail Gas Treating
Sulfur Degassing
Emission-Free Sulfur Recovery Unit
Sulfur Recovery—Oxynator™/OxyClaus™
FCC Gasoline—Prime-G+™
S Zorb™ SRT
Flue gas Cleaning—SNOX™
Tail gas treating
GT-BTX PluS®
Thiopaq O&G
HCR™
WWT Ammonia Recovery
Siirtec Nigi S.p.A.
Bechtel Hydrocarbon Technology Solutions Inc.
Siirtec Nigi S.p.A.
Shell Global Solutions International BV
Bechtel Hydrocarbon Technology Solutions Inc.
Bechtel Hydrocarbon Technology Solutions Inc.
Air Liquide
Axens
Haldor Topsoe
GTC Technology
Siirtec Nigi S.p.A.
Integrated Claus
Siirtec Nigi S.p.A.
Amec Foster Wheeler
Shell Global Solutions International BV
Shell Global Solutions International BV
Bechtel Hydrocarbon Technology Solutions Inc.
Air Liquide
Siirtec Nigi S.p.A.
Air Liquide
China Petrochemical Technology Co. Ltd
Amec Foster Wheeler
Shell Global Solutions International BV
Bechtel Hydrocarbon Technology Solutions Inc.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Distillation
Separation by boiling point: crude and vacuum, other products
Crude and vacuum distillation
Shell Global Solutions International BV
Crude Oil progressive
TechnipFMC
Deep-flash, high-vacuum distillation
Shell Global Solutions International BV
Divided Wall Column Technology
thyssenkrupp
GT-DWC℠
GTC Technology
Snamprogetti, Butene-1 recovery, (SP-B1)™
Saipem S.p.A.
Vacuum Distillation
thyssenkrupp
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Ethers
Typically produced through acid catalyzed dehyradation
Aerosol DME Process
thyssenkrupp
CDMtbe® and CDEtbe®
CB&I
CDTame® and CDTaee® from refinery C5 feeds
CB&I
ETBE Process
thyssenkrupp
Fuel DME Process
thyssenkrupp
MTBE/ETBE and TAME/TAEE
Axens
MTBE Process
thyssenkrupp
Snamprogetti™ Etherification Technology (SP-Ether)
Saipem S.p.A.
TAME from refinery and steam cracker C5 feeds
CB&I
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrocracking
Hydrogen reaction with high-MW fractions to alkanes, alkenes
Flexible, single-stage hydrocracking
Shell Global Solutions International BV
H-OilRC®
Axens
HyC-10™
Axens
Hydrocracking
Haldor Topsoe
HyK™
Axens
ISOCRACKING®
Chevron Lummus Global LLC (CLG)
LC-MAX
Chevron Lummus Global LLC (CLG)
Maximum (heavy) naphtha hydrocracking
Shell Global Solutions International BV
Mild hydrocracking
Shell Global Solutions International BV
Residue VCC
KBR Inc.
Two-stage, maximum diesel hydrocracking
Shell Global Solutions International BV
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation
Create hydrogen from natural gas or lighter refining fractions
Haldor Topsoe Convective Reformer (HTCR)
Haldor Topsoe
Heat Exchange Reforming (HTER)
Haldor Topsoe
Hydrogen by Steam Reforming
TechnipFMC
Pre-reforming with feed ultrapurification
Johnson Matthey
PRISM® Membranes
Air Products
PSA Purification
Air Liquide
SMR Production
Air Liquide
SMR-X™ Zero Steam Production
Air Liquide
Steam methane reformer (SMR)
Haldor Topsoe
Steam Methane Reforming
Linde Engineering North America Inc.
Terrace Wall™ reformer
Amec Foster Wheeler
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing
Remove impurities from fractions by treating with hydrogen
CDHydro®, CDHDS®, CDHDS+®
Hydrotreating
CDHydro® Hydrogenation
Hyvahl™
Fuel Gas Hydrotreatment (FGH)
ISOFINISHING®
Hydrodearomatization
IsoTherming® Technology
HydroFlex™
ISOTREATING®
Hydrogenation, CDHydro® benzene in reformate
MIDW™ technology
Hydrogenation, CDHydro® selective for refinery C4 feeds
OCR and UFR with RDS/VRDS
Hydrogenation, CDHydro® selective for refinery C5 feeds
Prime-D™
Hydrogenation, selective for MTBE/ETBE C4 raffinates
SCANfining™ technology
Hydrotreating
SLHT
CB&I
CB&I
Haldor Topsoe
Haldor Topsoe
Haldor Topsoe
CB&I
CB&I
CB&I
CB&I
Haldor Topsoe
Shell Global Solutions International BV
Axens
Chevron Lummus Global LLC (CLG)
DuPont Clean Technologies
Chevron Lummus Global LLC (CLG)
ExxonMobil Catalysts and Licensing LLC
Chevron Lummus Global LLC (CLG)
Axens
ExxonMobil Catalysts and Licensing LLC
China Petrochemical Technology Co. Ltd
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Internals
Process internals (typ. licensed) to improve performance
Adsorbents
BASF
Hydroprocessing Reactor
Haldor Topsoe
ISOMIX-e®
Chevron Lummus Global LLC (CLG)
Process Catalysts
BASF
Reactor internals
Shell Global Solutions International BV
Selective Catalytic Reduction
BASF
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Isomerization
Rearrange structure of a compound for desirable properties
GT-IsomPX℠
GTC Technology
Ipsorb™ and Hexorb™
Axens
Isomalk-2℠
GTC Technology
IsomPlus®
CB&I
MAX-ISOM™
KBR Inc.
Snamprogetti™ Iso/OctEne/Iso-OctAne Technology, (SP-Iso/SP-IsoH)
Saipem S.p.A.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes
Production of base oils for lubrication, and specialty waxes
BHTS Solvent Dewaxing
MP Refining
Conventional Group II/III base oils
MP Refining℠ Lube Extraction
Dewaxing
Naphthenic base oils
Extra-heavy base oils
Paraffinic base oils
Furfural refining
Revivoil™
Furfural Refining℠ Lube Extraction
Solvent Lube Dewaxing
Hydrofinishing/Hydrotreating
Solvent Wax Deoiling
Hy-Finishing℠ Lube Hydrotreating
Wax Fractionation℠ Solvent Dewaxing
Hy-Raff℠ Lube Hydrotreating
Wax Hy-Finishing℠ Hydrotreating
ISODEWAXING®
White Oil and Wax Hydrogenation
Bechtel Hydrocarbon Technology Solutions Inc.
Shell Global Solutions International BV
Haldor Topsoe
Shell Global Solutions International BV
thyssenkrupp
Bechtel Hydrocarbon Technology Solutions Inc.
thyssenkrupp
Bechtel Hydrocarbon Technology Solutions Inc.
Bechtel Hydrocarbon Technology Solutions Inc.
Chevron Lummus Global LLC (CLG)
thyssenkrupp
Bechtel Hydrocarbon Technology Solutions Inc.
Shell Global Solutions International BV
Shell Global Solutions International BV
Axens
thyssenkrupp
thyssenkrupp
Bechtel Hydrocarbon Technology Solutions Inc.
Bechtel Hydrocarbon Technology Solutions Inc.
thyssenkrupp
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Olefins
Create compound with double-bond for desired properties
Butenex® Process
thyssenkrupp
CRYO-PLUS™ Recovery of Olefins from Refinery Off-gas
Linde Engineering North America Inc.
FlexEne™
Axens
IPA Process
thyssenkrupp
MEK Process
thyssenkrupp
MIBK Process
thyssenkrupp
Polynaphtha™ and PolyFuel®
Axens
SBA Process
thyssenkrupp
Snamprogetti™, High-Purity Isobutylene, (SP-HPIB)
Saipem S.p.A.
TBA Process
thyssenkrupp
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Oxygen Enrichment
Use of oxygen (vs. air) for higher performance oxidation
Claus, oxygen-enriched
Siirtec Nigi S.p.A.
Claus units
Linde Engineering North America Inc.
FCC units
Linde Engineering North America Inc.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid
Non-hydrogen based treatment of gas or liquid impurities
AMINEX™ and AMINEX™ COS
Mericat™ and Mericat™ C
Aquafining™
Mericat™ J
BELCO® EDV® Wet Scrubbing
Mericon™
BenzOUT™ technology
Mericon™ II
Diesel Upgrading
NAPFINING™ and NAPFINING™ HiTAN
DynaWave® Wet Gas Scrubbers
OASE® yellow
FLEXSORB™ technology
Rectisol®
Gas treating
Refinery Fuel Additives
LO-CAT® H2S Removal Technology
REGEN®
LPG Sweetening—Sulfrex™
Shell CANSOLV® SO2 Scrubbing System
MECS® SolvR® Technology
Sour Gas Treatment
MECS® Spent Acid Recovery (SAR)
Spent acid regeneration
MECS® SULFOX™ Process
THIOLEX™
Mericat™ II
Ultra-low-sulfur diesel (ULSD)
Merichem Company
Merichem Company
DuPont Clean Technologies
ExxonMobil Catalysts and Licensing LLC
Haldor Topsoe
DuPont Clean Technologies
ExxonMobil Catalysts and Licensing LLC
Shell Global Solutions International BV
Merichem Company
Axens
DuPont Clean Technologies
DuPont Clean Technologies
DuPont Clean Technologies
Merichem Company
Merichem Company
Merichem Company
Merichem Company
Merichem Company
Merichem Company
BASF
Linde Engineering North America Inc.
BASF
Merichem Company
Shell Global Solutions International BV
Haldor Topsoe
Haldor Topsoe
Merichem Company
Haldor Topsoe
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Upgrading, Heavy Oil
Improve viscosity and other properties of heavy crude oils
Eni Slurry Technology (EST)
Eni S.p.A. Refining & Marketing
FLEXICOKING™ technology
ExxonMobil Catalysts and Licensing LLC
Gasification
Shell Global Solutions International BV
LC-SLURRY
Chevron Lummus Global LLC (CLG)
MPG™
Air Liquide
Resid to Propylene—R2P™
TechnipFMC
ROSE® plus Hydrocracker
KBR Inc.
Thermal gasoil process
Shell Global Solutions International BV
Visbreaking
Amec Foster Wheeler
Visbreaking
Shell Global Solutions International BV
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Air Liquide
PROCESSES
SERVICES
Air Liquide Engineering & Construction builds the Group’s production units
(mainly air separation and hydrogen production units) and provides external customers
with efficient, sustainable, customized technology and process solutions.
The company's core expertise in industrial gas, energy conversion and gas
purification enables customers to optimize natural resources. It covers the entire project
lifecycle: technology licensing, engineering services/proprietary equipment, high-end
engineering and design capabilities, project management and execution services.
Through Air Liquide Engineering & Construction's worldwide setup, it provides
efficient customer service and know-how, both locally and regionally. The technology
portfolio for the customers in the refining sector includes hydrogen, syngas, aromatics,
natural gas treatment, sulfur and biodiesel technologies.
As a technology partner, customers benefit from Air Liquide Engineering &
Construction's research and development efforts to help achieve energy transition goals.
CONTACT INFORMATION
Olot-Palme Str 35
60439 Frankfurt am Main
Germany
Phone: +49 69 580 80
europe.engineering@airliquide.com
www.engineering-airliquide.com/
Biofuels—Biodiesel—FAME
Desulfurization—Emission-Free Sulfur Recovery Unit
Desulfurization—SRU, TGT and Degas
Desulfurization—Sulfur Recovery—Oxynator™/OxyClaus™
Hydrogen Generation—PSA Purification
Hydrogen Generation—SMR Production
Hydrogen Generation—SMR-X™ Zero Steam Production
Upgrading, Heavy Oil—MPG™
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Air Products
SERVICES
Air Products is a world-leading industrial gases company that has been in
operation for more than 75 years. The company’s core industrial gases business provides
atmospheric and process gases and related equipment to manufacturing markets,
including refining and petrochemicals, metals, glass, electronics, and food and beverage.
Air Products is the world’s leading supplier of liquefied natural gas (LNG) process
technology and equipment, and owns and operates the world’s largest H2 pipeline.
CONTACT INFORMATION
7201 Hamilton Boulevard
Allentown, PA 18195-1501
Pone: +1 610-481-4911
Fax: +1 610-706-7394
membrane@airproducts.com
PROCESSES
Hydrogen Generation—PRISM® Membranes
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Amec Foster Wheeler
SERVICES
Amec Foster Wheeler designs, delivers and maintains strategic and complex
assets to maximize value to its customers across the oil and gas industry.
Our refining track record includes more than 40 new refineries and more
than 200 revamps, expansions, upgrades or turnarounds—many of which have
incorporated our licensed process technologies.
Our services cover the complete asset lifecycle, including conceptual designs,
feasibility studies, process design packages, project management, front-end
engineering design (FEED), detailed engineering, procurement, construction,
construction management, operation and maintenance, training and troubleshooting.
CONTACT INFORMATION
Energy Center I
585 North Dairy Ashford
Houston, Texas 77079
USA
Phone: 713-929-5000
www.amecfw.com
PROCESSES
Coking—SYDEC SM
Deasphalting—Solvent Deasphalting
Desulfurization—Modified Claus
Desulfurization—Tail gas treating
Hydrogen Generation—Terrace Wall™ reforming
Upgrading, Heavy Oil—Visbreaking
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Axens
SERVICES
Axens is a leading global provider of technologies, catalysts, adsorbents,
services and equipment. From oil refining, petrochemicals and gas processing,
to renewable and alternative fuels and water treatment, Axens solutions are used
at major industrial plants around the world
The company’s ambition is to provide sustainable and economically efficient
solutions for producing cleaner fuels and chemical intermediates from oil and
any other source of carbon, including bio-resources.
Backed by nearly 50 years of commercial success, Axens is a world leader in
several areas, including:
• Petroleum hydrotreating and hydroconversion
• FCC gasoline desulfurization
• Catalytic reforming
• BTX (benzene, toluene, xylenes) production and purification
• Selective hydrogenation of olefin cuts
• Sulfur recovery catalysts.
Axens is a fully-owned subsidiary of IFPEN.
CONTACT INFORMATION
89, Boulevard Franklin Roosevelt
92500 Rueil-Malmaison—France
Phone: +33 147 14 21 00
www.axens.net
PROCESSES
Alkylation—Selectopol™
Aromatics—Octanizing® and Aromizing™
Biofuels—Vegan®
Catalytic Cracking—Fluid Catalytic Cracking (FCC)
Catalytic Cracking—High Severity—HS-FCC™
Catalytic Cracking—R2R™
Catalytic Cracking—Resid to Propylene—R2P™
Desulfurization—FCC Gasoline—Prime-G+™
Ethers—MTBE/ETBE and TAME/TAEE
Hydrocracking—H-OilRC®
Hydrocracking—HyC-10™
Hydrocracking—HyK™
Hydroprocessing—Hyvahl™
Hydroprocessing—Prime-D™
Isomerization—Ipsorb™ and Hexorb™
Lubricants and Waxes—Revivoil™
Olefins—FlexEne™
Olefins—Polynaphtha™ and PolyFuel®
Treating, Gas/Liquid—LPG Sweetening—Sulfrex™
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
BASF
PROCESSES
SERVICES
At BASF, we create chemistry for a sustainable future. We combine economic
success with environmental protection and social responsibility. The approximately
114,000 employees in the BASF Group work on contributing to the success of our
customers in nearly all sectors and almost every country in the world. Our portfolio
is organized into five segments: Chemicals, Performance Products, Functional
Materials & Solutions, Agricultural Solutions and Oil & Gas.
The continuously rising demand for energy and resources requires us to develop
energy solutions that are more sustainable and address the need for energy efficiency
and conservation. With our knowledge and expertise in chemistry for oilfields,
refineries, mining, water, wind and solar energy, we partner with customers and share
their commitment to a healthier, more natural and more affordable future for energy
and resources. BASF’s offers for the refining industry include FCC refining catalysts,
process catalysts, adsorbents, OASE® yellow selective removal technologies for
selective treatment, flue gas desulfurization with formic acid or refinery additives.
CONTACT INFORMATION
www.basf.com
Catalytic Cracking—FCC
Catalytic Cracking—FCC Additive Technology
Catalytic Cracking—FCC Technology Platform Options
Internals—Adsorbents
Internals—Process Catalysts
Internals—Selective Catalytic Reduction
Treating, Gas/Liquid—OASE® yellow
Treating, Gas/Liquid—Refinery Fuel Additives
TECHNICAL ARTICLES
Back to basics: Maximizing octane barrels
New catalyst increases FCC Olefin Yield
Improve refining of tight oil via enhanced fluid catalytic cracking catalysts
We can sulfur problems: Catalyst solutions to meet Tier 3 regulations
Help improve FCC profit and performance through technical service
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Bechtel Hydrocarbon Technology Solutions Inc.
SERVICES
Bechtel Hydrocarbon Technology Solutions (BHTS) brings together industry
experts and leading technologies to deliver technology evaluation and front-end
engineering studies in the refining, petrochemicals, gasification and emerging energy
markets. BHTS complements Bechtel’s longtime record of engineering, procurement
and construction (EPC) excellence.
BHTS specializes in new technology development, value improvement practices,
de-bottlenecking studies, program management, technology licensor evaluations,
energy conservation and optimization, pre-commissioning and commissioning
assistance, technical audits and modularization. Our licensed technology offerings
include ThruPlus® delayed coking, Group I and II base oils technologies and sulfur
technologies.
CONTACT INFORMATION
3000 Post Oak Boulevard
Houston, Texas 77056, USA
Phone: +1 (713) 235-4300
bhts@bechtel.com
www.bechtel.com/bhts
PROCESSES
Coking—ThruPlus® Delayed Coking
Desulfurization—Amine Treating
Desulfurization—Claus Sulfur Recovery Units
Desulfurization—Claus Tail Gas Treating
Desulfurization—Sour Water Treating
Desulfurization—WWT Ammonia Recovery
Lubricant and Waxes—BHTS Solvent Dewaxing
Lubricant and Waxes—Furfural RefiningSM Lube Extraction
Lubricant and Waxes—Hy-FinishingSM Lube Hydrotreating
Lubricant and Waxes—Hy-RaffSM Lube Hydrotreating
Lubricant and Waxes—MP RefiningSM Lube Extraction
Lubricant and Waxes—Wax FractionationSM Solvent Dewaxing
Lubricant and Waxes—Wax Hy-FinishingSM Hydrotreating
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
CB&I
SERVICES
CB&I (NYSE:CBI) is a leading provider of technology and infrastructure for the
energy industry. With more than 125 years of experience, CB&I provides reliable
solutions to our customers around the world while maintaining a relentless focus on
safety and an uncompromising standard of quality.
• Technology licensing
• Engineering
• Procurement
• Fabrication
• Modularization
• Construction.
For more information, please visit our website at www.CBI.com and follow us on
our social media channels: YouTube, LinkedIn, Twitter and Facebook.
CONTACT INFORMATION
2103 Research Forest Drive
The Woodlands, Texas 77380
www.CBI.com
PROCESSES
Alkylation—AlkyClean®
Alkylation—Convert MTBE units, DIMER8 ®
Alkylation—Low-temperature acid catalyzed CDAlky®
Catalytic Cracking—Fluid catalytic cracking
Catalytic Cracking—IndmaxSM FCC for maximum olefins
Coking—Delayed coking
Ethers—CDMtbe® and CDEtbe®
Ethers—CDTame® and CDTaee® from refinery C5 feeds
Ethers—TAME from refinery and steam cracker C5 feeds
Hydroprocessing—CDHydro®, CDHDS®, CDHDS+®
Hydroprocessing—CDHydro® Hydrogenation
Hydroprocessing—Hydrogenation, CDHydro® benzene in reformate
Hydroprocessing—Hydrogenation, CDHydro® selective for refinery C4 feeds
Hydroprocessing—Hydrogenation, CDHydro® selective for refinery C5 feeds
Hydroprocessing—Hydrogenation, selective for MTBE/ETBE C4 raffinates
Isomerization—IsomPlus®
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Chevron Lummus Global LLC (CLG)
SERVICES
Chevron Lummus Global (CLG), a joint venture (JV) between Chevron U.S.A.
Inc. and CB&I, is a leading process technology licensor for refining hydroprocessing
technologies and alternative source fuels, as well as a global leader in catalyst system
supply. CLG offers the most complete bottom-of-the-barrel solution for upgrading
heavy oil residues. Our research and development experts are continuously seeking
advancements in technology and catalysts that will improve operating economics
for your next project. We provide unique, tailored solutions that are customized
to meet individual needs. By working with CLG, you will gain access to new
hydroprocessing technologies, catalysts and processes that will improve the success
of your refinery. We make this knowledge available to you through individualized
service and a worldwide technical support network that is second to none. We are
committed to helping refiners earn a rapid return on their investment, as well as
providing you with a flexible path for meeting more stringent future requirements.
The CLG team of research, development and process engineers, most with
hands-on operating experience, is ready to assist in any of the following areas:
• Process and design packages
• New product development and improvement
• Pilot plant studies
• Equipment evaluation
• Design follow-up
• Plant modification/optimization
• Operator training
• Startup assistance
• Debottleneck assistance
• Onsite technical support
• Procedures development
• Users’ seminars
• Refinery visits
• Technology updates
• Technology symposia
• Catalyst regeneration and disposal consultation.
CONTACT INFORMATION
100 Chevron Way, Suite 10-3336
Richmond, CA 94801
www.chevronlummus.com
PROCESSES
Coking—Delayed coking technology
Hydrocracking—ISOCRACKING®
Hydrocracking—LC-MAX
Hydroprocessing—ISOFINISHING®
Hydroprocessing—ISOTREATING®
Hydroprocessing—OCR and UFR with RDS/VRDS
Internals—ISOMIX-e®
Lubricants and Waxes—ISODEWAXING®
Upgrading, Heavy Oil—LC-SLURRY
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
China Petrochemical Technology Co. Ltd.
PROCESSES
SERVICES
China Petrochemical Technology Co. Ltd. (Sinopec Tech), as the licensing
platform and integrated solution provider of SINOPEC’s refining, petrochemical
and coal chemical technologies, offers global clients:
• Licensing—Proprietary technologies
• Products—Proprietary equipment and catalysts
• Service—Consultancy, PDP, FEED, BED, DED, procurement, construction,
commissioning, training, onsite service, EPC contracts, etc.
• More than 400 units utilizing SINOPEC technologies
• More than 20 yr of licensing experience dedicated to the refining
and petrochemical industries.
CONTACT INFORMATION
A6 Huixin East St.
Chaoyang District,
Beijing, China 100029
Phone: +86-10-6916-6661
g-technology@sinopec.com
sinopectech.com
Aromatics—LHAT-F
Aromatics—LHAT-M
Aromatics—S-CCCR
Aromatics—SED
Aromatics—S-TDT
Catalytic Cracking—FCC-MIP
Coking—Delayed coking
Desulfurization—S ZorbTM SRT
Hydroprocessing—SLHT
TECHNICAL ARTICLES
Consider new process for clean gasoline and olefins production
S-zorbTM Sulfur Removal Technology
Liquid Phase Hydrotreating Technology for Diesel
Counter-current Continuous Catalytic Reforming Process
S-TDT Process for Toluene Disproportionation and Transalkylation
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
DuPont Clean Technologies
SERVICES
DuPont technology experts in clean technology solutions can help transform
your organization’s complex industrial processes to improve quality and profitability,
while meeting environmental regulations.
Our innovative technologies help enhance health and safety, improve operational
efficiency and deliver competitive advantage. DuPont experts tailor our industryproven process technologies to help your organization formulate cleaner fuels, reduce
emissions, produce high-quality sulfuric acid, and much more. We can implement
breakthrough technologies and solutions across numerous complex processes, driving
business growth.
Our mission is to help you operate safely and with the highest level of confidence
by providing industry-leading technologies, world-class products and services,
and the people who know them best to allow you to operate with top performance,
reliability, energy, efficiency and environmental integrity.
CONTACT INFORMATION
6363 College Blvd, Suite 300
Overland Park, KS 66211, US
bioscience.dupont.com/clean-technologies/contact
www.dupont.com/products-and-services/clean-technologies.html
PROCESSES
Alkylation—STRATCO® Technology
Hydroprocessing—IsoTherming® Technology
Treating, Gas/Liquid—BELCO® EDV® Wet Scrubbing
Treating, Gas/Liquid—DynaWave® Wet Gas Scrubbers
Treating, Gas/Liquid—MECS® SolvR® Technology
Treating, Gas/Liquid—MECS® Spent Acid Recovery (SAR)
Treating, Gas/Liquid—MECS® SULFOX™ Process
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Eni S.p.A. Refining & Marketing
SERVICES
Technology licensing. Basic design package: Basic development activities, control
and approval of technical project documents (PFD, P&ID, heat and material balance,
equipment data sheet, operations manuals, notes to engineering contractors, etc.).
Supply of proprietary equipment: Equipment design, construction and supply
contract management. Supply of catalyst, operator training, pre-commissioning
and startup.
CONTACT INFORMATION
Via Laurentina, 449 – 00142 Rome–Italy
Phone: +39 06 59888922
Massimo.Trani@eni.com
www.eni.com
PROCESSES
Biofuels—Green Refinery/EcofiningTM
Upgrading, Heavy Oil—Eni Slurry Technology (EST)
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
ExxonMobil Catalysts and Licensing LLC
SERVICES
PROCESSES
Catalysts and Technology Licensing from ExxonMobil
ExxonMobil provides advantaged process technologies designed to meet
demands for refining high-quality lube base oils and premium petroleum fuels.
Our world-class refining technologies and high-value, proprietary catalysts—the same
innovations we use in our own facilities—offer environmental and economic benefits
across fuels dewaxing, lubes manufacturing and resid conversion technologies.
In our commitment to delivering safe and reliable technologies with long-term
value, we also offer cutting-edge solutions that help customers produce gasoline
(from methanol derived from natural gas, coal or biomass), olefins, xylenes and
other aromatics, as well as gas treating technologies.
Drawing from our decades of comprehensive operational expertise, we help
manufacturers implement best practices that not only encourage cost reduction
and margin improvement, but also grow high-value products and improve
environmental compliance, reliability and overall safety.
From capital project engineering and startup support to troubleshooting
and process control, we are dedicated to supporting success throughout the
industry, which is why we help our customers operate highly efficient facilities
every step of the way.
Alkylation—Sulfuric Acid Alkylation technology
Aromatics—Dividing wall column in xylenes services
Aromatics—EMHAI process
Aromatics—EMTAMSM process
Aromatics—MTDP-3 process
Aromatics—OlgoneSM process
Aromatics—PxMaxSM process
Hyrdoprocessing—MIDWTM technology
Hydroprocessing—SCANfiningTM technology
Treating, Gas/Liquid—BenzOUTTM technology
Treating, Gas/Liquid—FLEXSORBTM technology
Upgrading, Heavy Oil—FLEXICOKINGTM technology
CONTACT INFORMATION
22777 Springwoods Village Parkway
Spring, TX 77389
www.exxonmobilchemical.com/en/resources/contact-us
www.catalysts-licensing.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
GTC Technology
SERVICES
GTC Technology is a global licensor of process technologies and a manufacturer
of mass transfer equipment, and so provides processes and hardware that offer
custom solutions for the refining, chemical, petrochemical and gas processing
industries. Refining technologies include GT-BTX PluS® (desulfurization of FCC
gasoline with no octane loss), and Isomalk for light naphtha isomerization.
GT-STYRENE® (extractive distillation for styrene recovery) and GT-TransAlk℠
(transalkylation producing benzene and xylenes from toluene) are two of GTC’s
innovative petrochemical processes. GT-DWC® is an advanced distillation process
utilizing a contemporary version of a Dividing Wall Column, separating multicomponent feed into three or more purified streams within a single tower and
providing energy and equipment savings.
CONTACT INFORMATION
900 Threadneedle St., Suite 800
Houston, Texas 77079, United States
Phone: 281-597-4800
Inquiry@gtctech.com
www.gtctech.com
PROCESSES
Aromatics—GT-BenZap®
Aromatics—GT-BTX®
Aromatics—GT-BTX PluS®
Aromatics—GT-TransAlk℠
Desulfurization—GT-BTX PluS®
Distillation—GT-DWC℠
Isomerization—GT-IsomPX℠
Isomerization—Isomalk-2℠
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Haldor Topsoe
SERVICES
Optimal performance is built on great service and personal relationships that
grow stronger with each project successfully completed. No matter where you are
in the world, when you forge a relationship with Topsoe, you’ll meet expert scientists
and engineers with a genuine passion for your business success. Whether you’re
building a new product, unit or plant, or just want to optimize an existing one,
Topsoe offers the full range of engineering, technical, business and training services
you need. All our services are backed by deep scientific and engineering insight
and decades of hands-on technical experience. The earlier we get involved in your
project or specific challenge, the greater impact on performance we can have.
CONTACT INFORMATION
Haldor Topsoes Allé 1
DK-2800
Kgs. Lyngby
Denmark
Phone: +45 41964530
hehk@topsoe.com
www.topsoe.com
PROCESSES
Catalytic Cracking—FCC pretreatment
Desulfurization—Flue gas Cleaning—SNOX™
Hydrocracking—Hydrocracking
Hydrogen Generation—Haldor Topsoe Convective Reformer (HTCR)
Hydrogen Generation—Heat Exchange Reforming (HTER)
Hydrogen Generation—Steam methane reforming (SMR)
Hydroprocessing—Fuel Gas Hydrotreatment (FGH)
Hydroprocessing—Hydrodearomatization
Hydroprocessing—HydroFlex™
Hydroprocessing—Hydrotreating
Internals—Hydroprocessing Reactor
Lubricants and Waxes—Dewaxing
Treating, Gas/Liquid—Diesel Upgrading
Treating, Gas/Liquid—Sour Gas Treatment
Treating, Gas/Liquid—Spent acid regeneration
Treating, Gas/Liquid—Ultra-low-sulfur diesel (ULSD)
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Johnson Matthey
SERVICES
Johnson Matthey (JM) is a global specialty chemicals company underpinned by
science, technology and its people. A leader in sustainable technologies, many of the
group’s products enhance the quality of life of millions through their beneficial impact
on the environment, human health and wellbeing. JM products and services are sold
across the world to a wide range of advanced technology industries.
For the chemical, oil and gas industries, JM offers expertise in the design and
development of a range of DAVY™ licensed processes and technologies.
CONTACT INFORMATION
10 Eastbourne Terrace
London, W2 6LG, UK
Phone: +44(0) 207 957 4120
licensing@matthey.com
www.matthey.com
PROCESSES
Hydrogen Generation—Pre-reforming with feed ultrapurification
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
KBR Inc.
SERVICES
KBR Technology specializes in developing and licensing energy-efficient and
cost-effective process technologies that enhance the technical and economic
positions of global oil and gas and petrochemical companies. From co-developing
and commercializing the first fluid catalytic cracking (FCC) process unit in 1942, to
revolutionizing the fertilizer industry with the Kellogg ammonia process in the 1960s,
to commercializing heavy oil and coal monetization processes for a changing energy
landscape, KBR has been a pioneer and an industry leader.
KBR offers a breadth of technology licenses and process equipment for ammonia
and fertilizers, refining, olefins, coal gasification, syngas and hydrogen, organic and
specialty chemicals, and carbon capture and storage.
Our licensed technologies, whether full units or key equipment, can be found in
thousands of installations around the world. Our proprietary equipment is engineered
to perform, underpinning our continued commitment to performance and quality for
refining, coal gasification, petrochemicals, ammonia and syngas.
CONTACT INFORMATION
601 Jefferson St.
Houston, TX 77002
Phone: 713-753-2000
technologyconsulting@kbr.com
www.kbr.com
PROCESSES
Alkylation—K-SAAT™
Aromatics—AED-BTX
Catalytic Cracking—Orthoflow, ATOMAX™
Coking—Delayed coking
Deasphalting—ROSE®
Hydrocracking—Residue VCC™
Isomerization—MAX-ISOM™
Upgrading, Heavy Oil—Upgrading, Heavy Oil—ROSE® plus Hydrocracker
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Linde Engineering North America Inc.
PROCESSES
Hydrogen Generation—Steam Methane Reforming
Olefins—CRYO-PLUS™ Recovery of Olefins from Refinery Off-gas
Oxygen enrichment—Claus units
Oxygen Enrichment—FCC units
Treating, Gas/Liquid—Rectisol®
SERVICES
Linde Engineering (LE) is a member of The Linde Group, a world leading gases and
engineering company. LE is a single-source technology partner for plant engineering
and construction that provides a broad portfolio of plant process and equipment
solutions serving the refining, petrochemical, gas processing and chemical markets.
Trusted by clients in more than 100 countries, Linde has built more than 4,000
plants. Linde also supports operators with engineering, feasibility studies and services
to improve performance, feedstock flexibility and energy efficiency. We deliver costeffective solutions to improve efficiencies and recoveries, and continue to collaborate
with our customers to find the best solutions across the entire plant lifecycle.
CONTACT INFORMATION
12140 Wickchester Lane, Suite 300
Houston TX 77079, United States
Phone/Fax: 610-832-8757
sales@leamericas.com
www.LEAmericas.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Merichem Company
SERVICES
Merichem is a global partner serving the oil and gas industries with focused
technology, chemical and service solutions. Merichem provides the oil and gas
industry with critical proprietary impurity removal processes to increase the quality of
refinery products and gas streams. Merichem beneficially re-uses spent caustics and
other byproducts produced by oil refining and petrochemical plants around the globe.
We are also one of the leading suppliers of naphthenic acid and its derivatives in the
world. Merichem Process Technologies has been providing key proprietary refinery
product improvement technologies, many based on the FIBER FILM® technology for
more than 35 years. Merichem Gas Technologies provide proprietary solutions for
the removal of hydrogen sulfide (H2S) and other impurities from a wide-range of gas
applications. Merichem Caustic Services is the group that provides the beneficial reuse
option for refinery caustics, including the production of naphthenic acids. Merichem
Co. has been involved with refinery caustics for over almost all of its history.
CONTACT INFORMATION
5455 Old Spanish Trail
Houston, Texas 77023
Phone: 713-428-5000
www.merichem.com/company/contact-us
www.merichem.com
PROCESSES
Treating, Gas/Liquid—AMINEX™ and AMINEX™ COS
Treating, Gas/Liquid—Aquafining™
Treating, Gas/Liquid—LO-CAT® H2S Removal Technology
Treating, Gas/Liquid—Mericat™ II
Treating, Gas/Liquid—Mericat™ and Mericat™ C
Treating, Gas/Liquid—Mericat™ J
Treating, Gas/Liquid—Mericon™
Treating, Gas/Liquid—Mericon™ II
Treating, Gas/Liquid—NAPFINING™ and NAPFINING™ HiTAN
Treating, Gas/Liquid—REGEN®
Treating, Gas/Liquid—THIOLEX™
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Saipem S.p.A.
SERVICES
Saipem is one of the global leaders in the oil and gas market, providing
engineering, procurement, construction and installation of onshore plants, offshore
installations and pipelines, as well as in drilling services.
Saipem provides a full range of services, including the licensing of proprietary
technologies, and has distinctive capabilities and unique assets with the highest
technological content.
Saipem is able to take full responsibility for all phases of the project, from
feasibility studies to construction, startup and commissioning.
CONTACT INFORMATION
Via Martiri di Cefalonia, 67
20097 San Donato Milanese
Milano, Italy
Phone: +39 02 442 53462
maura.brianti@saipem.com
www.saipem.com
PROCESSES
Distillation—Snamprogetti, Butene-1 recovery, (SP-B1)TM
Ethers—SnamprogettiTM Etherification Technology (SP-Ether)
Isomerization—SnamprogettiTM Iso/OctEne/Iso-OctAne Technology,
(SP-Iso/SP-IsoH)
Olefins—SnamprogettiTM, High-Purity Isobutylene, (SP-HPIB)
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Shell Global Solutions International B.V.
SERVICES
Shell Global Solutions provides technical consultancy and licensed technologies
for the Shell Group and external customers within the energy industry. Shell Global
Solutions strives to deliver innovative technical solutions and effective technology
to support its customers in their day-to-day operations and delivery of strategic
plans to improve the capacity and performance of existing units, integrate new
process units into existing refineries and petrochemical complexes, and incorporate
advanced proprietary catalyst systems and reactor internals through to the design
of grassroots refineries.
Shell Global Solutions is affiliated with Shell’s catalyst companies,
which innovate and sell catalysts through a network that includes Criterion
Catalysts & Technologies, Zeolyst Intl., CRI Catalyst Co. and CRI Leuna.
CONTACT INFORMATION
Shell Global Solutions International B.V.,
Carel van Bylandtlaan 30,
2596 HR
The Netherlands
Postbus 162
2501 AN
www.shell.com/contact/globalsolutions
www.shell.com/globalsolutions
PROCESSES
Catalytic Cracking—Fluidized catalytic cracking
Desulfurization—CANSOLV® TGT+
Desulfurization—SCOT® (Shell Claus off-gas Treatment)
Desulfurization—Shell sulfur degassing
Desulfurization—Thiopaq O&G
Distillation—Crude and vacuum distillation
Distillation—Deep-flash, high-vacuum distillation
Hydrocracking—Flexible, single-stage hydrocracking
Hydrocracking—Maximum (heavy) naphtha hydrocracking
Hydrocracking—Mild hydrocracking
Hydrocracking—Two-stage, maximum diesel hydrocracking
Hydroprocessing—Hydrotreating
Internals—Reactor internals
Lubricants and Waxes—Conventional Group II/III base oils
Lubricants and Waxes—Extra-heavy base oils
Lubricants and Waxes—Naphthenic base oils
Lubricants and Waxes—Paraffinic base oils
Treating, Gas/Liquid—Gas treating
Treating, Gas/Liquid—Shell CANSOLV® SO2 Scrubbing System
Upgrading, Heavy Oil—Gasification
Upgrading, Heavy Oil—Thermal gasoil process
Upgrading, Heavy Oil—Visbreaking
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Siirtec Nigi S.p.A.
SERVICES
For more than 40 years, Siirtec Nigi has been providing its proprietary process
technology and tailor-made process solutions for cost-effective and dependable
sulfur recovery units.
Customers are assisted in their projects from inception until the completion
of turnkey plants. Siirtec Nigi also offers modular solutions to reduce site activities
and all major sulfur equipment, among which is its proprietary main burner.
Amine regeneration units, sour water strippers and mercaptan removal
supplement are part of Siirtec Nigi’s range of products for refineries.
CONTACT INFORMATION
Via Algardi, 2 – 20148 Milan, Italy
Phone: +39 0239223.1
Fax: +39 0239223.010
marketing@siirtecnigi.com
www.siirtecnigi.com/design-engineering-contracting
PROCESSES
Desulfurization—Advanced Ammonia Claus
Desulfurization—Ammonia Claus
Desulfurization—HCRTM
Desulfurization—Integrated Claus
Desulfurization—Sulfur Degassing
Oxygen Enrichment—Claus, oxygen-enriched
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
TechnipFMC
SERVICES
PROCESSES
ONSHORE
Catalytic Cracking—Deep Catalytic Cracking—DCC
Catalytic Cracking—FCC
Catalytic Cracking—High Severity HS-FCC™
Catalytic Cracking—Resid R2R™
Distillation—Crude Oil progressive
Hydrogen Generation—Hydrogen by Steam Reforming
Upgrading, Heavy Oil—Resid to Propylene—R2P™
TechnipFMC is a global leader in subsea, onshore/offshore and surface projects.
With our proprietary technologies and production systems, integrated expertise, and
comprehensive solutions, we are transforming our clients’ project economics.
Our employees are driven by a steady commitment to clients and a culture
of purposeful innovation, challenging industry conventions and rethinking how to
achieve the best results.
Our onshore business offers proprietary process technologies and know-how
in liquefied natural gas (LNG), gas processing, hydrogen (H2) /syngas, refining,
ethylene (C2H4), petrochemicals, polymers and renewables. Our global technology,
research and development, and consulting network is supported by our technology
laboratories in the United States and Europe.
Our core services include technology licensing, process design and engineering,
procurement and construction, proprietary equipment, project and construction
management, and consulting and feasibility studies.
We combine our technology expertise with proven engineering, procurement
and construction services to deliver turnkey projects to clients around the world.
Discover more about how we are enhancing the performance of the world’s
energy industry.
CONTACT INFORMATION
11740 Katy Freeway,
Energy Tower 3,
Houston, Texas 77079
Phone: +1 281 870-1111
Fax: +1 281 249-1742
steve.shimoda@technipfmc.com
TechnipFMC.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
thyssenkrupp
SERVICES
PROCESSES
The Power of True Efficiency
The Business Area Industrial Solutions of thyssenkrupp is a world leader
for planning, construction and service in the field of industrial plants and systems.
Together with our customers, we develop solutions at the highest level and deliver
efficiency, reliability and sustainability throughout the entire life-cycle. Our global
network, with around 19,000 employees at 70 locations, enables us to provide
turnkey solutions worldwide that set new benchmarks with their high productivity
and, in particular, resource-conserving technologies.
We are at home in many different industries: in addition to chemical, fertilizer,
coking, refining, cement and other industrial plants, our portfolio includes equipment
for open-pit mining, ore processing and transshipment, as well as associated
services. In the naval sector, we are a leading global system supplier for submarines
and surface vessels. As an important system partner to our customers in the
automotive, aerospace and battery industries, we optimize the value chain and
improve performance.
Aromatics—Morphylane® Process
Deasphalting—Solvent Deasphalting
Distillation—Divided Wall Column Technology
Distillation—Vacuum Distillation
Ethers—Aerosol DME Process
Ethers—ETBE Process
Ethers—Fuel DME Process
Ethers—MTBE Process
Lubricants and Waxes—Furfural refining
Lubricants and Waxes—Hydrofinishing/Hydrotreating
Lubricants and Waxes—MP Refining
Lubricants and Waxes—Solvent Lube Dewaxing
Lubricants and Waxes—Solvent Wax Deoiling
Lubricants and Waxes—White Oil and Wax Hydrogenation
Olefins—Butenex® Process
Olefins—IPA Process
Olefins—MEK Process
Olefins—MIBK Process
Olefins—SBA Process
Olefins—TBA Process
CONTACT INFORMATION
thyssenkrupp Industrial Solutions AG
ThyssenKrupp Allee 1/Essen, Germany
Phone: +49 6196 205-1750
Fax: +49 6196 205-1722
thomas.streich@thyssenkrupp.com
www.thyssenkrupp-industrial-solutions.com
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Alkylation—AlkyClean®
Application: The AlkyClean process converts light olefins into motor gasoline alkylate
by reacting the olefins with isobutane over a true solid acid catalyst. AlkyClean’s
unique catalyst system, reactor design and process scheme allow the refiner to
process light olefin streams (C3s, C4s and C5s) at moderate operating conditions while
producing an excellent quality alkylate product. AlkyClean is the only commercially
proven alkylation process that brings “peace of mind” to the refinery operations.
Hydrogen
Isobutane
Isobutane feed
Olefin feed
Reactor
system
(1)
Products: Alkylate is a high-octane, low-Rvp gasoline component used for blending
all grades of gasoline.
Product
distillation
(3)
n-Butane
Alkylate
product
Description: The light olefin feed is combined with the isobutane makeup and recycle
and sent to the alkylation reactors reactors operating in cyclincal mode, which convert
the olefins into alkylate using a solid acid catalyst (1). The AlkyClean process uses a
true solid acid catalyst to produce alkylate, eliminating the safety and environmental
hazards associated with liquid acid technologies. Simultaneously, other reactors are
undergoing a mild liquid-phase regeneration using isobutane and hydrogen (H2 ).
Periodically, a reactor undergoes a higher temperature vapor phase H2 strip (2).
The reaction effluent is sent to the product-fractionation section, which produces
n-butane, an alkylate product, while also recycling isobutene and recovering H2 used
in regeneration for reuse in other refinery hydroprocessing units (3). The AlkyClean
process does not produce any acid soluble oils (ASO) or require post treatment of the
reactor effluent or final products.
Reference: Medina, J., V. D’Amico, E. van Broakhoven and C. Zhao, “Successful
startup of the first solid catalyst alkylation unit,” AFPM Annual Meeting, San Francisco,
California, March 2016.
Product: The C5 + alkylate has a research octane number (RON) of 93–98,
depending on processing conditions and feed composition.
Licensors: Lummus Technology, a CB&I company, AlkyStar® catalyst is exclusively
available from Albemarle Catalysts.
Economics:
Contact: lummus.tech@cbi.com
Hydrogen
Catalyst
regeneration
(2)
Investment: $5,200/bpsd (2007 USGC basis 10,000-bpsd unit)
Utility and catalyst costs: $0.10/gal (2007)
Installation: A 2,700-bpsd alkylate production unit at Wonfull Petrochemical Co.,
Zibo, PR of China. Start-up occured in August 2015.
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Alkylation—Convert MTBE units,
DIMER8®
Application: The Dimer8 process uses a fixed-bed reactor followed by catalytic
distillation to achieve final isobutene conversion at high dimer selectivity. The Dimer8
process is the most attractive technology for converting a refinery-based methyl
tertiary butyl ether (MTBE) unit to isooctene/isooctane production.
Description: The selective dimerization of isobutenes over acidic ion-exchange resin
produces isooctene or di-isobutylene (DIB). Oxygenates such as methanol, MTBE,
water or tert-butyl-alcohol (TBA) are used as selectivators for the dimerization
reaction to prevent formation of heavier oligomers. The Dimer8 process uses
a fixed-bed reactor followed by catalytic distillation to achieve final isobutene
conversion at high dimer selectivity.
The primary fixed-bed reactor can be a boiling point reactor or a watercooled tubular reactor (WCTR). The choice will depend on the finished product and
operational requirements of the refiner. Either reactor can be used to achieve
high isobutylene conversion with excellent dimer selectivity.
The unique catalytic distillation (CD) column combines reaction and distillation
in a single unit operation. Continuous removal of heavier dimer product from
the reaction zone enables further conversion of isobutene without loss of dimer
selectivity. The use of CD eliminates the need for any downstream reaction/
fractionation system to achieve such performance.
Isooctene can be used as a gasoline blendstock due to its excellent
characteristics. Should olefin restrictions require a paraffinic product, the isooctene
product can be saturated to isooctane in a trickle-bed hydrogenation reactor.
Hydrogenation uses a base or noble metal catalyst, depending on the feed
contamination level.
Feed wash
Makeup oxygenate
Catalytic
Primary reactor
distillation column
Oxygenate
recycle
Oxygenate
recovery column
C4 raffinate
Water
C4 feed
Isooctene
Offgas
Wastewater
H2 feed
Olefin
saturation unit
Isooctane
Licensors: Jointly licensed Lummus Technology, a CB&I company, and Snamprogetti.
Contact: lummus.tech@cbi.com
Process advantages include:
• Easy implementation, minimum revamp changes, low capital cost,
short schedule
• > 90% isobutylene conversion
• > 80% C8 selectivity
• High flexibility
• Simple control
• High-octane/low-Rvp product for blending
• Low utility consumption.
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Alkylation—K-SAAT™
Recycle isobutane
Application: The KBR Solid Acid Alkylation Technology (K-SAAT) converts light
olefins (ethylene, propylene, butylenes and amylenes) to high-octane alkylate
using a zeolite-based, solid-acid catalyst. The engineered catalyst does not contain
any precious metals (e.g., platinum) and provides long alkylation cycle times.
The process uses a simple fixed-bed reactor design with a low catalyst inventory.
The technology can be used for grassroots alkylation units or retrofit existing liquid
acid alkylation units.
Products: Ultra-low-sulfur alkylate with high octane and low Reid vapor pressure
(RVP) as blending stock for gasoline.
Reactor
Olefin feed +
makeup IC4
Deisobutanizer
column
Description: The reactants (olefin feed and isobutane) are sent to a fixed-bed
alkylation reactor. The reactor converts 100% of the olefins to high-octane alkylate
using a solid acid catalyst. The K-SAAT process uses an engineered solid-acid catalyst
to maximize the yields and quality of the alkylate produced, while eliminating the
inherent safety concerns associated with liquid acid alkylation units.
The process employs two or three fixed-bed reactors—while one is operating in
regeneration mode, the other is operating in alkylation mode. The reactors are
typically designed for a 24-hr alkylation cycle before catalyst regeneration is required.
Catalyst regeneration is carried out with a circulating loop of hydrogen (H2 )-rich
hydrocarbon stream.
The reactor effluent is sent to a product fractionation section, where n-butane
and alkylate are separated and isobutane is recycled back to the reactor. The K-SAAT
process does not produce any acid soluble oil (ASO), and does not require any
product post treatment.
Advantages:
• Superior product quality. K-SAAT alkylate octane is higher than that produced
by liquid acid technologies with less than 1 ppm of sulfur.
• High yields of desired products. Reducing production of a heavy hydrocarbon
byproduct, with no production of ASO, the process produces a higher yield of
alkylate product per unit of olefin consumption.
• Feedstock flexibility. The K-SAAT technology can process a wide range
of feedstocks, including ethylene, propylene, butylenes and amylenes.
• Lower capital cost. The simple, fixed-bed reactor design does not require
lined vessels or acid containment equipment, or refrigeration compressors.
N-butane
Alkylate
Reactor
Compressor
Continued 
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Alkylation—K-SAAT (cont.)
• High efficiency with low power consumption. K-SAAT operates above ambient
temperature and eliminates the need for power intensive refrigeration.
• Safety. KSAAT catalyst is safe and environmentally benign.
• Easy to retrofit. K-SAAT can easily replace an existing alkylation reaction section,
or take advantage of spare fractionation capacity by an add-on approach.
Capital Investment: A grassroots project costs about $6,000/bpd, while a revamp to
replace a reaction section would be about $3,600/bpd.
Yields and Octanes:
Feed type
RON
MON
Vol/vol olefins
MTBE
raffinate
99
95
1.84
FCC
olefins
97
93
1.88
Isobutylenes
95
92
1.95
Propylene
(50 wt%)
94
91
1.82
Installation: First commercial unit starting in December 2017
Licensor: KBR Inc. and Excelus
Contact: technologyconsulting@kbr.com
Amylene
91
89
2.22
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Alkylation—Low-temperature
acid catalyzed CDAlky®
Propane to storage
Application: The patented CDAlky process is an advanced sulfuric acid catalyzed
alkylation process for the production of motor fuel alkylate.
Description: The CDAlky low-temperature sulfuric acid alkylation technology
reacts light olefin streams with isoparaffins to produce motor fuel alkylate.
Central to the CDAlky process is a novel, scalable contactor/reactor design equipped
with proprietary internals to provide enhanced distribution and mass transfer
without the use of agitators. The separation of the acid-hydrocarbon emulsion,
downstream of the reactor, is easy because the acid-hydrocarbon emulsion droplet
size distribution is optimized. This has eliminated the need for caustic and water
washing of the reactor effluent, which is required for conventional alkylation
processes because of the associated carryover problems. With no rotating mixers
or caustic and water post-treatment steps, the CDAlky flow scheme is less complex,
requires less capital, improves operational reliability and reduces corrosion rates
in the downstream product fractionation section. The CDAlky process yields
a higher quality product while consuming significantly less acid than conventional
sulfuric acid-based technologies.
The CDAlky process is highly flexible due to the innovative reactor design.
The CDAlky reactor can operate in a wide range of operating conditions (65°F to
below 32°F), which allows optimized performance as a function of the feedstock
being processed. CDAlky is suitable for processing all types of olefins such as fluid
catalytic cracking (FCC) olefins, refinery grade propylene, dehydrogenated isobutane
and amylenes.
Advantages: The benefits of the CDAlky process include:
• Reduced operating cost
• Reduced environmental footprint and safety exposure
• Higher octane product, higher yield and lower acid consumption
• Lower CAPEX—simpler flowsheet with fewer pieces of equipment
• Lower maintenance—no mechanical agitator or complex seals
• Less corrosion due to dry system and lower operating temperature
• No caustic waste stream.
DeC3
iC4 recycle
Olefin feed
iC4 makeup
Fractionator
Reaction
Separation
n-Butane to storage
Alkylate product to storage
Acid recycle
Fresh acid
Spent acid
Licensor: Lummus Technology, a CB&I company
Installations: CDAlky technology has been commercialized since 2013, and more than
10 awards have been received since 2012. An installed capacity of nearly 130,000 bpd
is expected by 2020.
Contact: lummus.tech@cbi.com
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Alkylation—Selectopol™
Application: Conversion of isobutylene contained in C4 cuts into high-octane
compounds for gasoline blending, and n-butenes-rich stream for further
applications in refining and petrochemicals
Description: The Selectopol process is a variant of the Polynaphtha™ process,
using the same proprietary IP 811 catalyst but at lower severity. It enables the
selective conversion of the isobutene portion of an olefinic C4 fraction to
high-octane, low-RVP gasoline blending stock; and the enrichment of the
trimethyl pentene stream for petrochemical applications.
IP 811 is a specific high-selectivity promoted catalyst that is specially
designed to ensure long operation cycles, and with high mechanical strength.
Multiple regenerations, in-situ or ex-situ, can be supported to restore the activity
without altering mechanical properties
Selectopol is typically fed with C4 olefinic cuts produced downstream of the
FCC, steam cracking, dehydrogenation or coker units. Isobutylene is oligomerized
catalytically in the liquid phase in fixed-bed reactors in series. Conversion and
selectivity are controlled by reactor temperature adjustment. The reactor section
effluent is fractionated producing n-butene raffinate depleted in sulfur and olefins,
and a gasoline fraction that can be used as high-octane blending stocks for the
gasoline pool. Isobutylene conversion ranges typically between 90%–99%,
depending on feedstock quality and product distribution.
Enriched n-butenes raffinate of Selectopol is ideally sent to an alkylation,
methyl ethyl ketone (MEK), metathesis or Dimersol-X process without
pretreatment. This isobutene dimerization technology provides a low-cost
means of retrofitting existing MTBE units, or debottlenecking existing alkylation
units by converting all isobutene and a small percentage of the n-butenes,
without need for additional isobutane.
The oligomerization product is mostly composed of olefins. Depending on
local constraints in olefins specifications—as a reference, Euro 5 sets a level of 18 vol%
limit for gasoline—controlling the olefins content of the products may be required.
The Selectopol gasoline RON and MON obtained from FCC C4 cuts are
significantly higher than those of FCC gasoline; additionally, they are sulfur-free.
Hydrogenation improves the MON, whereas the RON remains high and close to
that of C4 alkylate.
Licensor: Axens
References:
Dubin, G., M.-P. Esnaola, M. Godard-Pithon and A. Pucci, “Alternatives to alkylation:
Flexible approaches for light olefin management vital for the dynamic fuels
market,” AFPM 2017, San Antonio, Texas.
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/
73/oligomerization.html
Contact: www.axens.net/contact.html
Installations: To date, Axens has been awarded with more than 20 references
for its oligomerization technologies (Polynaphtha™, PolyFuel®, Selectopol™
and FlexEne™), and several units are now in operation worldwide.
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Alkylation—STRATCO® Technology
Application: The STRATCO alkylation technology combines propylene, butylenes
and/or amylenes with isobutane in the presence of a strong sulfuric acid catalyst
to produce high-octane, branched chained hydrocarbons for use in motor fuel and
aviation gasoline. The resulting clean-burning alkylate is high-octane, low Rvp,
low sulfur and zero olefins.
Description: The STRATCO alkylation units are designed to process propylene,
butylenes and/or amylenes, either individually or as a mixture. Olefins and isobutanerich streams, along with a catalyst stream of sulfuric acid (H2SO4 ) are charged to
the STRATCO Contactor™ reactor (1). The liquid contents of the Contactor reactor
are circulated to create an optimized amount of interfacial area between the reacting
hydrocarbons and the acid catalyst from the acid settler (2). This circulation ensures
that the entire volume of liquid in the Contactor reactor is maintained at a uniform
temperature, with less than 1°F between any two points within the reaction mass.
The Contactor reactor products pass through a flash drum (3) and deisobutanizer (4).
The refrigeration section consists of a compressor (5) and depropanizer (6).
The overhead from the deisobutanizer (4) and effluent refrigerant recycle (6)
constitutes the total isobutane recycle to the reaction zone. This total quantity of
isobutane and all other hydrocarbons is maintained in the liquid phase throughout
the Contactor reactor, thereby serving to promote the alkylation reaction.
Onsite sulfuric acid regeneration (SAR) technology is also available.
Operating conditions: Key operating parameters include reactor temperature,
olefin space velocity, H2SO4 strength, isobutane-to-olefin ratio and interfacial area
between the hydrocarbon and catalyst.
Advantages: The STRATCO alkylation technology offers several key advantages:
• Flexibility to process different feed types (propylene, butylenes and amylenes,
including 100% isobutylene feeds)
• Olefin conversion of 100% and olefin-free alkylate product
• Optimized reaction operating parameters
• High reliability and unit uptime
• Optimized mixing
• Proven best-in-class operations and product quality (alkylate octane,
sulfur content, endpoint, Rvp) with decades of supporting data.
Propane product
5
2
3
6
4
n-Butane product
1
Alkylate product
Olefin feed
i-Butane
Installations: The STRATCO technology has more than 90 licenses worldwide,
with nearly 950,000 bpd of installed capacity.
Licensor: DuPont Clean Technologies
Website: www.dupont.com/products-and-services/clean-technologies/products/
stratco-alkylation-technology.html
Contact: bioscience.dupont.com/clean-technologies-contact
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Alkylation—Sulfuric Acid
Alkylation technology
Propane product
Refrigeration
Application: ExxonMobil offers proven light ends upgrading technology
for alkylate production.
Compressor
Description: Upgrading light olefins and isobutene to alkylate offers refiners an
opportunity to increase their crude barrel value. Alkylate is a superior gasoline
blendstock due to its high octane and low-vapor pressure. ExxonMobil’s proven
Sulfuric Acid Alkylation technology reacts propylene, butylene and pentylene
with iso-butane to form high-value alkylate for gasoline blending.
Advantages: The advantages of this technology include:
• ExxonMobil’s experience in inventing, designing and operating the technology
• High reliability in line with FCC cycles
• Less major equipment
• Up to 10,000 bpd reactor capacity produces economies of scale
• Direct vaporization of C3 results in energy savings
• Multiple mixing zones in the reactor increases reliability
• More than 50 years of ExxonMobil and licensee operating experience
from 2,000 bpd–100,000 bpd
• Flexibility in partnering with multiple sulfuric acid (H2SO4 ) regeneration
technologies
Fractionator
Olefins feed
Reactor and settler
ExxonMobil’s robust
reactor design
Butane product
Recycle iC4
iC4 feed
Alkylate product
Licensor: ExxonMobil Catalysts & Licensing LLC
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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Aromatics—AED-BTX
Application: The AED-BTX process is a new extractive distillation (ED) technology
for aromatics recovery, which can recover benzene, toluene and C8 aromatic
hydrocarbons, while simultaneously achieving more than 30% savings in energy
compared to conventional liquid-liquid extraction (LLE) processes.
Description: For the ED process to achieve acceptable levels of aromatics purities and
recoveries, the solvent must retain essentially all the benzene (NBP 80°C), which is the
lightest aromatic compound in the bottom of extractive distillation column (EDC), and
drive virtually all of the heavy C8+ non-aromatics (NBP > 130°C) to EDC overhead.
Full-range aromatic hydrocarbons from pyrolysis gasoline, reformate or
coke oven oil are preheated and sent to the middle of the EDC, while lean solvent
(sulfolane) from the bottom of the solvent recovery column (SRC) (after a series of
heat recoveries and cooling) is fed to the top of the EDC. After ED, the non-aromatics
(raffinate) exit from the top of the EDC, while rich solvent, which contains aromatics
(extract) and lean solvent, exits from the bottom. Raffinate is sent to the water wash
drum (not shown) to be contacted with water to remove any entrained solvent.
The final raffinate product exits from the top of the water wash drum. Rich
solvent from the bottom of the EDC is pumped to the middle of the SRC to separate
aromatics (extract) from solvent. Extract exits from overhead of the SRC as aromatics
product, while lean solvent leaves from the bottom and recycles back to the EDC.
Conventional ED processes require proprietary solvents, are limited to a narrow
feedstock boiling-range (applicable to benzene or benzene/toluene recovery only),
and frequently accumulate heavy hydrocarbons in lean solvent. All of these contribute
to high CAPEX and OPEX.
Highlights of this new ED process technology include: the effective recovery
of butane, toluene and xylene (BTX) aromatics directly from full range (C6–C8 )
reformate or pygas feedstocks without precutting C8+ components; the use of the
original sulfolane solvent as the ED solvent without modification; the application of
proprietary process and mass-transfer equipment designs and operation in the ED
column to achieve effective three-phase (L+L+V) fractionation; and the control of
heavy hydrocarbons in the lean solvent to maintain optimum solvent performance.
P6/N6/P7/N7/P8/N8/P9/N9 non-aromatic raffinate
Lean solvent
50°C
P6
N6
B
P7
N7
T
P8
N8
X/EB
P9
N9
140°C
Non-aromatics
B/T/X/EB aromatic extract
Extractive
distillanation
column
HC feed
Aromatics
Extractive
stripper
Steam
Rich solvent
Installations: Two installations are now in operation.
References:
“Advanced Aromatics Recovery Technology with AED-BTX Process,”
AICHE Spring Meeting and Global Congress on Process Safety, April 28, 2015.
Licensor: KBR Inc.
Contact: technologyconsulting@kbr.com
Advantages: The AED-BTX process maximizes operating benefits through an
achieved 35%–38% savings in energy consumption (compared to the extractive
stripper in prior LLE units), increases unit throughput for same-vessels diameters as
conventional LLE, does not require anti-foam agent, and offers a further reduction of
ED unit operating expenses.
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Aromatics—Dividing wall column
in xylenes services
A
Application: ExxonMobil’s dividing wall columns (DWCs) design and operational
know-how in aromatics facilities.
Description: DWC technology is widely deployed in the petrochemical industry, but
its use in aromatics complexes is limited. DWCs offer significant potential for energy
and capital savings vs. conventional multi-column arrangements in services such as
reformate splitting or butane, toluene or xylene (BTX) fractionation. Other benefits
include a smaller plot area, shorter piping and reduced flare load. ExxonMobil has
developed a unique capability in engineering, design, operation and control of DWCs
for aromatics services.
Advantages: The technological advantages include:
• Improved thermal efficiency
° Typically, approximately 30% lower energy consumption vs.
conventional fractionation
• Capital efficiency (one column, one reboiler, one condenser)
° Usually 20%–40% savings vs. conventional fractionation
• Reduced plot size
• ExxonMobil unique design and operational know-how
° Partition design
° Partition placement and orientation
° Dynamic modeling
° Control schemes
° Sensitivity to changes in operating conditions
• Product specification, feed rate, feed composition, temperature, etc.
A+B
Dividing wall
B
A, B, C
B+C
C
Licensor: ExxonMobil Catalysts & Licensing LLC
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
Installations: At present, four DWCs are in operation at ExxonMobil and licensees’
aromatics plants, and gather more than 20 yr of commercial experience. Additional
grassroots deployments are planned in 2019 and 2020.
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Aromatics—EMHAI process
Application: ExxonMobil’s EMHAI process is the vapor-phase isomerization
of choice for sites using crystallization for paraxylene (pX) separation.
Description: The EMHAI process features a low-cost, high-activity catalyst,
which can be operated at very-high weight hourly space velocity compared to
other processes. It is well-suited for debottlenecking small xylenes isomerization
vessels, or for plants operating a crystallization unit. This advantage is possible
because EMHAI performance is not affected by pX content in the crystallization
effluent. Benzene product purity exceeds 99.9%, which makes EMHAI ideal
for retrofit at facilities with limited extraction capacity.
Advantages: EMHAI’s advantages include:
• Smaller units, grassroots
• Higher capacity, revamps
• Low xylene losses
• Negligible aromatic ring loss
• High pX approach to equilibrium
• High ethylbenzene conversion
• Benzene product with greater than 99.9% purity
• Consistent yields and conversion across extremely long cycles.
Paraxylene
H2
Paraxylene recovery
C9 + heart-cut
Xylene
splitter
Gas
EMHAI process
Benzene/toluene
Stabilizer
Orthoxylene
Orthoxylene
tower
C9+ aromatics
Installations: The technology, commercialized since 2009, has exhibited excellent
and stable performance in several licensees’ sites. Typically, EMHAI services include
consultation from the design through startup phases of project implementation,
and beyond.
Licensor: ExxonMobil Catalysts & Licensing LLC (or Axens for grassroots
aromatics complexes)
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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Aromatics—EMTAM℠ process
Application: ExxonMobil’s toluene alkylation with methanol process (EMTAM).
Description: The EMTAM process is the latest addition to ExxonMobil’s portfolio of
technologies for paraxylene (pX) production. The EMTAM process employs a fluidizedbed reactor based on ExxonMobil’s extensive experience and know-how in fluid
catalytic cracking (FCC) design and operation. The EMTAM process key features are
a proprietary staged methanol injection system and an ex-situ selectivated catalyst,
which allow high toluene conversion per pass with very-high selectivity to pX.
Fluidized-bed toluene methylation enables long cycles at stable conversion
and yields that are otherwise unachievable with conventional fixed-bed processes.
Benzene can be co-fed for additional pX production, which provides a unique ability to
respond to market changes. While the EMTAM process offers advantages on its own,
significant additional advantages can be obtained in a grassroots aromatics complex
when the unit is included in the initial design. Further savings can be achieved by
combining the EMTAM process with ExxonMobil’s LPI process, which isomerizes the
xylenes post-recovery in the liquid phase.
Advantages: The EMTAM process advantages include:
• Low cost of pX production (feedstock and energy)
• Fluidized-bed technology for long, stable cycles
• High toluene conversion per pass
• Very high selectivity to pX
° pX recovery costs are considerably reduced
• High methanol utilization
• Unlimited benzene co-feeding capability
• No aromatic ring loss
• No hydrogen (H2 ) co-feeding
• Low catalyst cost
• Low byproduct make.
Installations: With EMTAM services, you can typically expect technical assistance
and support from design through the startup phases of project implementation and
beyond. These benefits may include:
• Detailed yield estimates and feasibility study
• Formal licensing proposal with disclosures and negotiations, enabling you
to utilize specific technologies and produce specified products at your site
• Technology transfer, startup and regeneration support
• Technology improvement exchange and access to next-generation technologies.
Licensor: ExxonMobil Catalysts & Licensing LLC (or Axens for grassroots
aromatics complexes)
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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Aromatics—GT-BenZap®
Offgas
Application: GTC Technology’s GT-BenZap is a benzene saturation technology
that allows refiners to achieve the benzene limit required by EPA regulations under
Mobile Sources Air Toxics Phase 3 (MSAT3), Euro 6 and BS 6. Benzene saturation is
applied when the logistics of benzene recovery and production are unfavorable, or
where the economy of scale for benzene production is not sufficient.
Description: GT-BenZap features a traditional design paired with a proven nickelbased catalyst. The process consists of hydrotreating a narrow-cut C6-cut fraction,
which is separated from full-range reformate, to saturate the benzene component
into cyclohexane. The reformate is first fed to a reformate splitter where the C6
cut is separated as a top fraction, while the C7+ cut is removed as bottom product.
The hydrogenated C6-cut fraction from the reactor outlet is sent to a stabilizer column,
where the remaining hydrogen (H2 ) and lights are removed overhead.
As the hydrotreated C6 cut is mixed with the C7+ cut from the splitter column,
full-range reformate that is low in benzene forms. GTC also offers a modular
construction option and the possibility to reuse existing equipment.
Alternatively, when possible and economically justified, the reformate splitter
column may be converted from a conventional fractionation overhead column to
a dividing wall column (DWC). In this case, the reformate is first fed to a reformate
splitter (internally provided with a dividing wall) where the C6 heart-cut is separated
as a side-draw fraction, while the C7+ cut and the C5 light fraction are removed as
bottom and top products of the column. The hydrogenated C6 heart-cut fraction
from the reactor outlet is sent to a stabilizer column, where the remaining H2 and
lights are removed overhead. The C5 cut, produced from the splitter overhead,
can be recombined with the hydrogenated C6 heart-cut or sent to an isomerization
unit, increasing the value potential of this fraction.
After stabilization, the C6 heart-cut is mixed with the C7+ cut from the splitter
column and together form the full-range reformate, which is low in benzene.
By using DWC technology, approximately 20%–30% in energy consumption of
the entire process can be realized.
Operating conditions: The reactor operates at normal, mild hydrotreating pressure
(approximately 25 bar–30 bar), with an operating temperature of less than 150°C.
The reformate splitter column operates at atmospheric pressure.
Yields: Yields depend on the capacity and reforming unit type. The benzene
concentration in the reformate is key in defining the capacity/yield of the unit.
Offgas
C6-rich with
benzene
Stabilizer
Full-range reformate
Reformate
splitter
H2
Low-benzene gasoline
blend stock
C7+
To isomerization unit
Off-gas
Off-gas
C5
DWC
Full-range reformate
Stabilizer
C6- rich with
benzene
Reformate
splitter
H2
C7+
Low-benzene gasoline
blend stock
Continued 
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Aromatics—GT-BenZap® (cont.)
Advantages:
• Simple and reliable technology, low operating costs—particularly when
the DWC option is applied to the reformate splitter and the reactor section
is unloaded significantly
• An economical alternative to platinum-based systems; less catalyst required
• Lower fresh H2 makeup required compared with other technologies
• Ability to reduce the benzene in the reformate stream by more than 99.9%
• The technology also was successfully applied to food-grade solvents produced
by small refineries where benzene must be eliminated completely from
the C5–C6 fraction.
Utilities: Dependent on the size/capacity of the reforming units, but also on
the amount of benzene content into the feed stream. Generally, the more benzene
in the feed, the more utilities consumed.
Development/Delivery: All of the tower and reactor internals are GTC
proprietary devices.
Installations: Four commercial licenses.
Licensor: GTC Technology, Licensing Department
Website: www.gtctech.com
Contact: inquiry@gtctech.com
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Aromatics—GT-BTX®
Application: GT-BTX is an aromatics recovery technology that uses extractive
distillation to remove benzene, toluene and xylene (BTX) from refinery or
petrochemical aromatics streams, such as catalytic reformate or pyrolysis gasoline.
With lower capital and operating costs, simplicity of operation, and range of feedstock
and solvent performance, extractive distillation is superior to conventional liquid-liquid
extraction processes. Flexibility of design allows use for grassroots aromatics recovery
units, debottlenecking or expansion of conventional extraction systems.
Description: Hydrocarbon feed is preheated with hot circulating solvent and fed at
a midpoint into the extractive distillation column (EDC). Lean solvent is fed at an
upper point to selectively extract the aromatics into the column bottoms in a vapor/
liquid distillation operation. The nonaromatic hydrocarbons exit the top of the column
and pass through a condenser. A portion of the overhead stream is returned to the
top of the column as reflux to wash out any entrained solvent. The balance of the
overhead stream is raffinate product and does not require 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 hydrocarbon stripping. The SRC is operated under a vacuum to
reduce the boiling point at the base of the column.
Lean solvent, from the bottom of the SRC, is passed through heat exchange
before returning to the EDC. A small portion of the lean circulating solvent is
processed in a solvent regeneration step to remove heavy decomposition products.
The SRC overhead mixed aromatics product is routed to the purification section,
where it is fractionated to produce chemical-grade BTX.
Operating conditions:
S/F ratio*
EDC bottom temperature*
SRC bottom temperature
2.5 v/v–3.5 v/v
155°C–170°C
< 180°C
*Reformate feed only
Products: For typical feed as defined in Application.
Benzene purity
99.99%
Toluene purity
99.98%
Aromatics recovery
99%
Solvent losses
Negligible
Raffinate
Lean solvent
Hydrocarbon feed
Extractive
distillation
column (EDC)
Solvent
recovery
column
Aromatics to
downstream
fractionation
Aromatics-rich solvent
Advantages: The advantages of GT-BTX include:
• Lower capital cost compared to conventional liquid-liquid extraction
or other extractive distillation systems
• Energy integration options to further reduce operating costs
• Higher product purity and aromatic recovery
• Recovers aromatics from full-range BTX feedstock
• Distillation-based operation provides better control and simplified operation
• Proprietary formulation of commercially available solvent exhibits high
selectivity and capacity
• Low-solvent circulation rates
• Insignificant fouling due to elimination of liquid-liquid contactors
• Fewer hydrocarbon emissions sources for environmental benefits.
Continued 
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Aromatics—GT-BTX® (cont.)
Economics/Investment:
Feed rate
ISBL capital cost
New Unit
12 Mbpd reformate or pygas
$15 MM
Utilities:
Electricity
MP steam
Cooling water
Licensor: GTC Technology US LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
1,255 kWh
72 Mtph
202 M3/h
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Aromatics—GT-BTX PluS®
Application: GT-BTX PluS is an extractive distillation process to convert fluid catalytic
cracking (FCC) gasoline into high-value aromatics, particularly for high-severity
or petro-FCC type.
Description: This process separates the aromatics plus sulfur components from cracked
gasoline to permit recovery of the aromatics as petrochemical product. A mid-cut of
FCC gasoline is fed to an extractive distillation operation that selectively removes the
aromatics and sulfur species from the olefinic-rich gasoline. The extract is subsequently
hydrodesulfurized to remove the sulfur species. The streams may be blended together
as gasoline with no change in octane value from the raw cut, or the aromatics may be
fed directly to the fractionation section of a paraxylene (pX) plant. The olefinic-rich nonaromatics may also be converted to aromatics via a fixed-bed aromatization process.
Operating conditions:
S/F ratio*
EDC bottom temperature*
SRC bottom temperature
Full-range
FCC naphtha
HDS
BTX fraction
Feed
fractionation
HDS
Gasoline
2.5 v/v–3.5 v/v
155°C–170°C
< 180°C
*Reformate feed only
Yields:
Aromatics recovery
Solvent losses
GT-BTX PluS
Economics: Feedrate: 20,000 bpd; 70°C–150°C range of FCC gasoline products—
> 99%
Negligible
Process Advantages:
• Eliminates FCC gasoline sulfur species to meet a pool gasoline target
of 10 ppm sulfur
• Rejects olefins from being hydrotreated in the HDS unit to prevent loss
of octane rating and to reduce hydrogen (H2 ) consumption.
• Fewer components (only the heavy-most fraction and the aromatic concentrate
from the ED unit) are sent to hydrodesulfurization (HDS), resulting in a smaller
HDS unit and lower yield loss
• Purified benzene and other aromatics can be produced from the aromatic-rich
extract stream after hydrotreating
• Olefin-rich raffinate stream (from the ED unit) can be directed to an
aromatization unit to produce additional BTX, or recycled to the FCCU
to increase light olefin production
• Effective means of benzene reduction from FCC source of gasoline without
loss of octane.
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
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Aromatics—GT-TransAlk℠
Application: GT-TransAlk produces benzene and xylenes from toluene and/or
heavy aromatics streams. The technology features a proprietary catalyst and
can accommodate varying ratios of feedstock, while maintaining high activity
and selectivity.
Description: The technology encompasses three main processing areas: splitter,
reactor and stabilizer sections. The heavy-aromatics stream (C9 + feed) is fed to
the splitter. The overhead C9 /C10 aromatic product is the feed to the transalkylation
reactor section. The splitter bottoms are exchanged with other streams for heat
recovery before leaving the system.
The C9 /C10 aromatic product is mixed with toluene and hydrogen (H2 ),
vaporized and fed to the reactor. The reactor gaseous product is primarily unreacted
H2, which is recycled to the reactor. The liquid product stream is subsequently
stabilized to remove light components. The resulting aromatics are routed to
product fractionation to produce the final benzene and xylene products.
The reactor is charged with zeolite catalyst, which exhibits both long life
and good flexibility to feed stream variations, including substantial C10 aromatics.
Depending on feed compositions and light components present, the xylene yield can
vary from 25%–37%, and C9 conversion from 53%–77%.
Advantages:
• Simple, low-cost, fixed-bed reactor design, drop-in replacement
for other catalysts
• Very high selectivity, benzene purity is 99.9% without extraction
• Physically stable catalyst
• Flexible to handle up to 90%+ C9 and components in feed with high conversion
• Catalyst is resistant to impurities common to this service
• Moderate operating parameters, catalyst can be used as replacement
to other transalkylation units or in grassroots designs
• Decreased H2 consumption due to low cracking rates
• Significant decrease in energy consumption due to efficient heat integration
scheme.
Recycle plus
make-up H2
Toluene (optional)
C9/C10
Charge heater
Light HC
Recycle gas
Heavy aromatics
Feed
splitter
Reactor
Stabilizer
Separator
C11+
Aromatics to
product
fractionation
Investment: Feed 1 MMtpy (22,000 bpd); erected (excluding feed splitter) at a cost
of $18 MM (ISBL, 2017 US Gulf Coast Basis).
Installations: Three commercial licenses
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
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Aromatics—LHAT-F
Application: SINOPEC’s light-hydrocarbon aromatization technology in a fixedbed reactor (LHAT-F) uses cylindrical, zeolite catalyst to convert C2–C10 lighthydrocarbon feedstocks to aromatics—mainly into benzene, toluene and xylenes
(BTX), or aromatics-rich gasoline blending components with a high-octane number.
Description: Targeting different products, the SINOPEC LHAT-F process can be
classified into three application schemes: aromatics, feed for ethylene plants and
gasoline-oriented. The LHAT-F process is mainly used for the production of gasolineblending components with a high-octane number. Suitable feeds are mainly olefincontained fluid catalytic cracking (FCC) dry gas, liquefied petroleum gas (LPG)
and light naphtha.
When using FCC dry gas as feedstock, the gasoline yield is generally between
12%–18%, and the research octane number (RON) is between 92–94. When effluent
C4 LPG from the methyl tertiary butyl ether (MTBE) unit is used as feedstock,
the gasoline yield is generally between 30%–40%, the RON is between 92–94
and the dry gas yield is less than 2%. When naphtha is used as feedstock,
the gasoline yield is generally between 65%–75%, the RON is between 85–90
and the dry gas yield is less than 2%.
The running period of a single run is generally 2 mos–4 mos. The whole running
cycle can be up to 3 yr.
Installations: SINOPEC’s LHAT-F packaged process has been applied
in more than 20 units. The largest unit has a capacity of 400,000 tpy.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
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Aromatics—LHAT-M
Application: SINOPEC’s light-hydrocarbon aromatization technology using
a moving bed reactor (LHAT-M) adopts spherical zeolite catalyst to convert C2–C10
light hydrocarbon feedstocks to aromatics—mainly into benzene, toluene and xylenes
(BTX), or an aromatics-rich gasoline blending component with a high-octane number.
Description: The LHAT-M process can be classified into three application schemes:
aromatics, feed for ethylene plants and gasoline-oriented. For the LHAT-M process,
liquefied petroleum gas (LPG) and light naphtha are the main feedstocks used.
The main products produced are mixed aromatics, saturated liquefied petroleum
gas (LPG) that can be used as feed for ethylene plants, and hydrogen (H2 ).
When the target product is aromatics, the yield ranges between 50%–60%,
the yield of saturated LPG is between 20%–30%, and the H2 yield is generally
between 2.5%–3.5%. The circulating period is between 4 d–7 d. The whole running
period can be up to 3 yr.
The LHAT-M process provides refiners with the flexibility to operate the unit
under high-severity conditions.
Installations: The LHAT-M process has been applied in two industrial plants,
with the largest unit having a capacity of 200,000 tpy. At the time of this publication,
a 500,000 tpy unit was being designed and constructed.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
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Aromatics—Morphylane® Process
Nonaromatics
Application: The recovery of high-purity aromatics from reformate, pyrolysis gasoline
or coke oven light oil using extractive distillation (ED).
Description: In thyssenkrupp’s proprietary extractive distillation Morphylane process,
a single-compound solvent—N-formylmorpholine (NFM)—alters the vapor pressure
of the components being separated. The vapor pressure of the aromatics is lowered
more than that of less soluble non-aromatics.
Non-aromatics vapors leave the extraction section with some solvent, which is
recovered in a short distillation section of the top of the column.
The bottom product of the ED column is fed to the stripper to separate pure
aromatics from the solvent. After integrated heat exchange, the lean solvent is
recycled to the ED column. NFM satisfies the necessary solvent properties by
providing high selectivity and capacity, thermal stability and a suitable boiling point.
As further development of the thyssenkrupp DWC technology, thyssenkrupp’s
single-column Morphylane process uses a divided wall column configuration, which
integrates the ED column and stripper column, representing a superior process option
in terms of investment and operating cost.
The former proprietor of this process is ThyssenKrupp Uhde GmbH.
Advantages:
• Proven technology for all kinds of BTX feedstock
• Low investment due to low number of equipment and carbon steel
as material of construction
• High on-stream times by operating with a non-toxic solvent having
no corrosive effect, no fouling tendency, and low sensitivity to oxygen
• Discontinuous low solvent make-up rates leading to low operating cost
• Extensive heat integration to further reduce energy consumption
• Beneficial olefin selectivity to raffinate product (non-aromatics) resulting
in high RON/MON values
• High aromatic product purities of greater than 99.95 wt% for Benzene
and TDI grade Toluene at minimum cost
Extractive
distillation
column
Feedstock
Aromatics
Stripper
column
Solvent + aromatics
Solvent
Installations: More than 75 Morphylane plants with a total combined capacity in
excess of 15 MMtpy. The first single-column Morphylane unit went onstream in 2004.
Licensor: thyssenkrupp
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com, dorothe.weimer@thyssenkrupp.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
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Aromatics—MTDP-3 process
Application: ExxonMobil’s state-of-the-art processes for toluene disproportionation.
Description: ExxonMobil’s MTDP-3 process is the state-of-the-art process
for toluene disproportionation to benzene and mixed xylenes. The technology,
based on a proprietary zeolite catalyst, offers high product yields at high toluene
conversion. MTDP-3 is ideal for toluene upgrade to more valuable chemicals,
without investing in paraxylene (pX) separation facilities. Benzene product exceeds
99.9% purity, so additional extraction capacity is not required. MTDP-3 has been
operated commercially at multiple licensees sites for more than 20 yr.
Advantages: MTDP-3 technology advantages include:
• Very high toluene conversion per pass
• High benzene product and mixed xylenes product yields
• High weight hourly space velocity
• Superior xylenes/benzene ratio
• Benzene product with greater than 99.9% purity
• Very low hydrogen (H2 ) consumption
• Low catalyst cost
• Low operating cost
• Long catalyst cycles with stable product yields across the cycle.
Recycle toluene
C 5–
99.9+% benzene
Mixed xylenes
H2
Stabilizer
Toluene
Benzene
column
Toluene
column
Xylene
column
MTDP-3 process
C9+ aromatics
Licensor: ExxonMobil Catalysts & Licensing LLC (or Axens for grassroots
aromatics complexes)
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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2017 REFINING PROCESSES HANDBOOK
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Aromatics—Octanizing® and
Aromizing™
Regenerator
Reactors and heaters
Application: Upgrade various types of naphtha to produce high-octane reformate,
BTX (benzene, toluene, xylenes) and liquefied petroleum gas (LPG).
Description: Two different catalytic reformer designs are offered. The first is
a semi-regenerative design where the catalyst is regenerated in-situ at the end
of each cycle. Operating normally in a pressure range of 12 kg/cm2–25 kg/cm2
(170 psig–350 psig) and with low pressure drop in the hydrogen (H2 ) loop,
the product is 90 RONC–100 RONC. With higher selectivity and stability, the PR150
series featuring multi-promotors formulation
serves as an excellent catalyst replacement for semi-regenerative reformers.
The second design, the advanced CCR Reforming, uses continuous catalyst
regeneration, allowing operating pressures as low as 3.5 kg/cm2 (50 psig). This is
made possible by smooth-flowing moving bed reactors (1–3), which use a highly
stable and selective catalyst suitable for continuous regeneration. The Octanizing
process is dedicated to gasoline applications, whereas the Aromizing process has
been developed for high-severity operations with the objective to produce BTX.
The main features of Axens’ regenerative technology are:
• Side-by-side reactor arrangement, which is very easy to erect
and consequently leads to low investment costs
• The RegenC-2 catalyst regeneration system featuring the dry burn loop
completely restores the catalyst activity while maintaining its specific area
for more than 600 cycles.
Finally, the new generation of Axens CCR catalyst, CR 157 (gasoline mode) and
AR 151 (aromatics production), provides high selectivity and a significant improvement
in activity vs. commercially available catalyst from the market. Thanks intrinsic catalyst
properties and effective catalyst regeneration design, high levels of performance
are achieved with these new generations over the entire catalyst life.
Yields: Typical for a 90°C–170°C (176°F–338°F) cut from light Arabian feedstock:
Conventional
Octanizing/Aromizing
Operation press, kg/cm2
10–15
3–7
Yield, wt% of feed:
Hydrogen (H2 )
2.8
3–4
C5+
83
88–93
RONC
100
100–105
MONC
89
89–92
✓Open source DCS cat.
circulation and ref.
Net gas
compressor
H2-rich gas
Recovery
system
Feed
Recycle
compressor
Reformate
to stabilizer
Process Flow Diagram: On the hydrocarbon side, the process scheme is typical of a
conventional reforming unit, with three or four reactors in a side-by-side arrangement,
and intermediate heaters to compensate for reactions endothermicity.
After the reaction section, the net vapor and the liquid product from the reaction
section enter a cold re-contacting section to maximize LPG and gasoline recovery and
achieve good H2 purity. The reformate is then sent to the stabilizer to reach ultimate
recoveries of LPG and C5+ effluent in the bottom.
On the catalyst side, circulation is established from the bottom of one Rx to
the top of the following with lift gas. The catalyst flows downward through the first
reactor, and is collected in the bottom hopper before being sent to the first lift pot.
The lift pot conveys the catalyst by way of the lift line to the upper hopper of the
second reactor, from which the catalyst will flow through the second reactor and up
to the regeneration tower. The catalyst goes through the various regeneration steps
flowing down the regeneration tower.
Once regenerated, it is lifted to the top of the first Rx and passes through a
reduction chamber before entering the first reactor.
Continued 
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Aromatics—Octanizing® and Aromizing™ (cont.)
Installations: Of 185 units licensed, 125 units are designed with continuous
regeneration technology capability.
References:
1. “Increase reformer performance through catalytic solutions,” Congrès ERTC 7th
annual meeting, Paris, France, November 2002.
2. “Squeezing the most out of fixed-bed reactors,” Hart Show Special, National
Petrochemical and Refiners Association (NPRA, now AFPM) Annual Meeting,
2003.
3. “Octanizing reformer options to optimize existing assets,” National Petrochemical
and Refiners Association (NPRA, now AFPM) Annual Meeting, 2005.
4. Boitiaux, J. P., et al., “New developments accelerating catalyst research,”
Hydrocarbon Processing, pp. 33–40, September 2006.
5. “Advances in naphtha processing for reformulated fuels production,” National
Petrochemical and Refiners Association (NPRA, now AFPM) Annual Meeting,
2010.
6. “Redefining reforming catalyst performance: High selectivity and stability,”
Hydrocarbon Processing, September 2012.
Licensor: Axens
Website: www.axens.net/our-offer/by-market/oil-refining/top-of-the-barrel/23/
catalytic-reforming—-continuous-gasoline.html
Contact: www.axens.net/contact.html
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Aromatics—Olgone℠ process
Application: ExxonMobil’s leading-edge aromatic streams treatment.
Description: A high-performance, highly-stable catalyst is at the heart of
ExxonMobil’s Olgone process. This technology is designed to extend cycles of
existing aromatic streams treaters, reducing the amount of solid waste that is
generated. The outstanding performance of the Olgone process can lead to
significant operating cost savings, as well as debottlenecking opportunities.
Advantages: Advantages of the Olgone technology include:
• Extended cycles (single-catalyst cycle equivalent to up to six clay cycles)
• Regenerable catalyst can be reused with minimum activity loss
for subsequent cycles
• Simple “drop-in” replacement for clay
• Reduced solid waste
• Fewer costly change-outs
• More stable operations
• Increased protection for downstream units
• Lower investment costs.
B/T cut
Reformate feed
Extraction
Benzene
B/T frac
Fractionation
section
Toluene
Transalkylation unit
Olgone process
C 8+ A
Olgone process
Paraxylene
C8+A
fractionation
section
C9/C10A
Xylene
isomerization
PX product
C11+A
Installations: Since 2003, several commercial units have begun operations at
ExxonMobil affiliates’ and licensees’ sites.
References:
• Kerze, A. D., T. F. Kinn and T. Sato, “Upgrade treatment operations
for aromatics units,” Hydrocarbon Processing, April 2007.
Licensor: ExxonMobil Catalysts & Licensing LLC (or Axens for grassroots
aromatics complexes)
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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Aromatics—PxMax℠ process
Application: ExxonMobil’s state-of-the-art processes for selective toluene
disproportionation.
Description: Exxonmobil’s PxMax process is the industry benchmark for
selective toluene disproportionation (STDP). The technology, based on the exsitu selectivated EM-2300 catalyst, offers unmatched paraxylene (pX) selectivity
and product yields, as well as exceptionally long and stable cycles. ExxonMobil’s
dividing wall column (DWC) technology and crystallization recovery technology
are also available for licensing in combination with the PxMax process. Most STDP
units worldwide operate the PxMax process, with catalyst cycles exceeding 13 yr in
multiple locations.
Advantages: PxMax advantages include:
• Improved process performance
° Ultra-high pX selectivity, which improves over the cycle
° High weight hourly space velocity
° Higher total xylenes yield
° Superior xylenes/benzene ratio
° Benzene product with greater than 99.9% purity
° Very low hydrogen (H2) consumption
° Lower operating cost
• Extremely long catalyst cycles—no in-situ selectivation needed
• Lower investment costs
° Reduced size of reactor and PX recovery unit
° Lower metallurgy cost.
Recycle toluene
C5–
Paraxylene
Paraxyleneenriched
xylenes Paraxylene
recovery
99.9+% benzene
H2
Stabilizer
Toluene
Benzene
column
Toluene
column
Xylene
column
PxMax process
Paraxylenedepleted mixed
xylenes
C9+ aromatics
Installations: PxMax services typically include consultation from design
through the startup phases of project implementation and beyond.
Licensor: ExxonMobil Catalysts & Licensing LLC (or Axens for grassroots
aromatics complexes)
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
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Aromatics—S-CCCR
Application: SINOPEC’s counter-current continuous catalytic reforming (S-CCCR)
process, characterized by a novel counter-current circulation of catalysts, converts
refinery naphtha into high-octane liquid products that are premium blending stocks
for high-octane gasoline and butane, toluene and xylenes (BTX) production.
Description: The regenerated catalyst enters the last reactor, where it is sent to
the first reactor, while the feed still flows from the first reactor to the last one.
Thus, the catalyst has the highest activity in the last reactor and the lowest activity
in the first reactor. The high-activity catalyst is used to promote the difficult reactions,
and the low-activity catalyst is used for the easy reactions. So, the process makes
the catalyst activity match the difficulty of the reaction.
Advantages: SINOPEC’s S-CCCR process not only improves reaction conditions,
but also creates a new catalyst circulation method with a simplified operation.
The benefits of the S-CCCR process include:
• Compared with the co-current process, the yields of C5+ product
can be increased from approximately 0.5% to 1%, and hydrogen (H2 )
from 5% to approximately 10%.
• Reactors are arranged side-by-side. The specifications of four reactors
are identical, so that design, fabrication, installation and maintenance
are much easier than for reactors of different specifications. Spare parts
are universal for four reactors.
• The average reaction pressure and the pressure of the gas-liquid separator
are kept at 0.35 MPag and 0.24 MPag, respectively.
• Catalyst transportation from low-pressure to high-pressure is achieved by
means of catalyst sealing legs, rather than the complicated lock-hopper
and relevant control system.
• The process is simplified by the design of a spend catalyst dust elutriation
system due to the dramatic decreases of catalyst attrition.
• The burning zone in the catalyst regeneration section consists of two moving
beds. The bed temperature increases gradually so that temperature runaway
can be avoided.
Reference:
1. Hong, D., “Technical progress in refining and petrochemical industry,”
China Petrochemical Press, pp. 3–8, 2015.
2. Dai, H., “Aromatics production technology,” China Petrochemical Press,
pp. 67–71, 2015.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
Installations: The first 600,000 tpy S-CCCR unit was put into operation in 2013.
In 2016, the second unit, with a total capacity of 1 MMtpy, went into operation.
At the time of this publication, three additional reformers were under design.
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Aromatics—SED
Application: SINOPEC’s sulfolane extractive distillation (SED) process is an extractive
distillation process using sulfolane and co-solvent to recover high-purity benzene, or
benzene and toluene from hydrocarbon mixtures such as pyrolysis gasoline, reformate
or coke oven light oil.
Description: The typical SED process consists of an extractive distillation (ED) column
and a solvent recovery (SR) column. The hydrocarbon feed is sent to the ED column,
where the non-aromatics are directly removed through extractive distillation by
solvents. Next, the rich solvent from the bottom of the ED column is sent to the SR
column, where the overhead aromatics are separated from the solvent by vacuum
distillation, and the bottom-lean solvent is recycled to the ED column.
Advantages: The advantages of the SED process include:
• Process flexibility: The SED process can be combined with the liquid-liquid
extraction (LLE) process to expand capacity of the existing LLE unit.
The combination process, which includes a new SED unit and an unchanged
LLE unit, has the advantages of a lower investment and few influences on
the operation of the LLE unit during revamping.
• Feedstock flexibility: The SED process is suitable for any kind of feedstock,
either with high-aromatics content, such as pyrolysis gasoline and coke oven oil,
or with low-aromatics content, such as reformate C6 cut.
• Efficiency: Through the combination of a high-performance extractive solvent,
optimized process and advanced control strategy, the SED process is able to
produce high-quality aromatics with high-recovery efficiency. The purity of the
main products (benzene and toluene) adopting SED reaches 99.9%, while the
recovery efficiency is between 99.5%–99.9 %.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
Installations: By 2017, SED technology has been licensed to 60 commercial units, with
a total capacity of 6.1 MMtpy of benzene and 6.4 MMtpy of toluene. The maximum
capacity in a single SED unit is 1 MMtpy.
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Aromatics—S-TDT
Application: SINOPEC’s toluene disproportionation and transalkylation (S-TDT)
process was developed for the production of mixed xylenes and benzene through
the disproportionation of toluene and the transalkylation of toluene and C9+
aromatics. C9 and C10 aromatics, from hydrotreated pyrolysis gasoline or reformate,
can be upgraded to high-value benzene and xylenes.
Description:
• HAT-series catalysts with high-activity, selectivity, good operational stability
and feedstock flexibility are designed for the S-TDT process. They offer the
efficient upgrade of low-value heavy aromatics to high-value-added target
aromatics products.
• Low-value C9 aromatics can be upgraded to high-valued xylenes products
via transalkylation. By changing the ratio of toluene/C9 aromatics in the
feedstock, the proportion of xylene and benzene in the products can be
adjusted accordingly.
• Up to 20 wt% of C10 aromatics, in the aromatics feedstock, can be handled
to effectively increase the production of xylene.
• Benefiting from the patented gas distributor and gas collector in the large,
axial-flow fixed-bed reactor, the resulting uniform distribution of reactants
ensures the best catalyst performance.
• Heat integration technology is adopted to reduce energy consumption.
A high-efficiency welded-plate heat exchanger is used for inlet/outlet heat
exchange in the reactor to fully recover the heat from the reaction.
Installations: There were nine S-TDT units built up by the end of 2016. The largest
unit has a maximum capacity of 1.8 MMtpy. At the time of this publication, three
units were under construction. Two of the units each have a total capacity of
330,000 tpy, with an additional unit with a capacity of 510,000 tpy.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
References:
1. Xie, Z., W. Yang, D. Kong and D. Zhu, “Process for selective disproportionation
of toluene and disproportionation and transalkylation of toluene and
C9+ aromatics,” United States Patent 6774273, 2004.
2. Kong, D., D. Yang, H. Li, H., Guo and T. Ruan, “Process for the disproportionation
and transalkylation of toluene and heavy aromatics,” United States Patent
7109389, 2006.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Biofuels—Biodiesel—FAME
Application
Biodiesel (fatty acid methyl ester, or FAME) produced from vegetable or animal
oils and fats. Major feedstock for fuel applications are rapeseed, soya, tallow and palm
oil, with coproduct of crude glycerin (purity > 80%).
Description
Biodiesel is produced from triglycerides by transesterification with methanol
under the presence of alkali catalyst (sodium methylate) at approximately 60°C and
atmospheric pressure. Standard capacities are 100 tpd–1,100 tpd.
Only NaOH and HCl are used in the process. The resulting sodium chloride ends
up in the glycerin, can be easily removed and does not cause fouling or side reactions
during further processing. This crude glycerin can be distilled and bleached to produce
pharma-grade glycerin.
Advantages
Biodiesel meets all international quality standards, including EN 14214 and
ASTM D6751.
Key features of the biodiesel technology are maximum yield (1 kg feedstock =
1 kg biodiesel), closed wash water loop (no wastewater from core process units) and
sediment removal for palm and soya oil to remove sterol glucosides far below limits
given by international quality standards.
Hydrogenation of glycerin to propylene glycol creates another value-added
product to petrochemical industry through the Bio PG process.
Oils and fats
Oils refining
NaOH
Methanol catalyst
HCI
Transesterification
Glycerin water pretreatment
and evaporation
Washing and drying
sediment removal
Crude glycerin
concentration > 80 %
Biodiesel
“ready-to-use”
Economics
OPEX: $7 MM–$12 MM
Installations
More than 50 plants since 2000 (Europe, Americas, Southeast Asia, India).
Website: https://www.engineering-airliquide.com/oleochemicals
Contact
oleo@airliquide.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Biofuels—Green Refinery/Ecofining™
Application: The Green Refinery project refers to the conversion of a conventional
petroleum refinery into a biorefinery by means of Ecofining technology, jointly
developed by Eni/UOP. Ecofining™ can process vegetable oils and animal fats into
green diesel and other fuels.
This innovative idea (patent No. MI2012A001465 filed in September 2012)
will contribute to promoting the industrial application of Ecofining™ technology
to reduce investment costs and speed up the construction of a biorefinery.
Description: The Ecofining process consists of two stages of reactions: in the first
stage, triglycerides contained in the biological feedstock are completely deoxygenated
under hydrogen (H2 ) partial pressure in a sour environment on a proprietary metallic
catalyst, producing a mix of linear paraffins, carbon dioxide (CO2 ) and water.
The product of the first stage is then processed in a second stage of reaction,
where this mix of linear paraffins is isomerized—always under the partial pressure
of H2 —over a proprietary catalyst to branch the linear chains for the improvement
of the final products’ cold-flow properties.
The Ecofining™ process maximizes green diesel production, and also produces
green naphtha, green liquefied petroleum gas (LPG) and (optionally) green jet,
each one valued as bio-components for transportation fuels.
The core of the Green Refinery project, implemented at the Venice refinery,
is the conversion of two existing HDS units into Ecofining. In particular, the first unit
(HDS 1) is converted to a hydro-deoxygenation section, mainly replacing the existing
desulphurization catalyst with the proprietary deoxy catalyst, along with other minor
modifications to the existing plant. The product of this first step of reactions is sent
to the second existing HDS unit (HDS 2), where linear paraffins are isomerized,
thanks to a specific isomerization catalyst.
Operating conditions:
• Hydro-deoxygenation section: average conditions 270°C and 30 barg
• Isomerization section: average conditions 320°C and 60 barg.
Yields: Typical product yields:
Diesel, wt%
Naphtha, wt
Propane, wt%
Water, wt%
CO + CO2, wt%
75–85
1–8
4–5
6–8
3–4
Advantages: One of the main advantages of the Ecofining process is the possibility
to control the cold-flow properties of the main product, green diesel, due to the
second stage of the reaction, which also allows it to easily reach Alpine quality
(cloud point –20°C).
Green diesel is an optimum biocomponent for blending in diesel fuel (EN590)
without limitations. The product has higher heating value and energy density
than fatty acid methyl esters (FAME), a high cetane number, low density and no
aromatics. Diesel fuels formulated with significant percentages of hydrotreated
vegetable oil (HVO) have shown a reduction of polluting emissions in light- and
heavy-duty vehicles and NOx in heavy-duty vehicles
The Green Refinery project has all the advantages of a revamping project.
Integration with existing facilities provides utilities, ancillaries and offsite support.
In addition, the conversion to a biorefinery consistently reduces total
environmental impact.
Continued 
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COMPANY INDEX
Biofuels—Green Refinery/Ecofining™ (cont.)
Economics:
Investment: The revamping of the existing units in Venice sped up the realization
of the project, significantly reducing the required investment cost, estimated at about
25% of a new Ecofining™ grassroots unit of the same capacity.
Utilities: Specific consumption per ton of fresh feed:
Specific consumption
Venice Green Refinery
Fuel gas, tons
–0.032
LP steam, tons
–0.35
MP steam, tons
–3.04
CW, m3
41
Electricity, MWh
0.08
Development/Delivery: Eni/UOP’s joint R&D activities began pursuing a patent in
2007 for a new hydrotreatment process, called Ecofining™, for the production of a new
type of biofuel that was totally hydrocarbon, predominately green diesel of excellent
quality, and independent from the renewable feedstocks used.
The Green Refinery project began at Eni’s Venice refinery in 2013. In May 2014,
the production of green fuels started.
Installations: Eni’s Venice refinery, with a capacity of 400,000 tpy, is the only
industrial application of the Green Refinery project. The plant can process a wide
range of vegetable oils, animal fats, fatty and cooked oils. A new section for the
treatment of crude palm oil (POT) is under construction and will be onstream by the
end of 2017.
A second Green Refinery with a capacity of 710,000 tpy is under construction at
Eni’s Gela refinery and will be operational in 2018.
References:
1. Rispoli, G., A. Amoroso and C. Prati, “Venice biorefinery: How refining
overcapacity can become an opportunity with an innovative idea,”
Hydrocarbon Processing, Vol. 92 No. 2, February 2013.
2. Cavani, F., S. Albonetti, F. Basile and A. Albonetti, Chemical and Fuels from
Bio-Based Building Blocks, Wiley-VCH 2016, Vol. 1, Ch. 5, May 2016.
3. Holmgren, J., C. Gosling, R. Marinangeli, T. Marker, G. Faraci and C. Perego,
“New developments in renewable fuels offer more choices,” Hydrocarbon
Processing, September 2007.
Licensor: UOP and Eni have a commercial agreement for licensing the jointly
developed Ecofining technology, including the conversion of a petroleum refinery into
a biorefinery. UOP is responsible for the licensing.
Website: www.eni.com/en_IT/innovation/technological-platforms/green-refinery.page
Contact: www.uop.com/processing-solutions/renewables/green-diesel/ecofining/
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Biofuels—Vegan®
Application: Hydroprocessing of renewable lipids, such as fats and oils, into drop-in
middle distillate biofuels.
Description: The Vegan technology has the flexibility to process all available
vegetable oils and animal fats, as well as future lipidic feedstock (such as algal oil).
Hydrotreatment of lipids leads to the production of oxygen, sulfur and aromaticfree high-cetane linear (normal) paraffins. The n-paraffins are often called “waxes”
and have poor cold flow properties. An isomerization step is required to upgrade
these n-paraffins into diesel or jet fuel, and bio-based premium blendstocks that meet
international specifications.
The tuning of the isomerization operating conditions allows the plant to match
the required boiling range and cold-flow properties of the product, whatever the
feedstock characteristics.
Vegan technology is based on proprietary catalyst and enables:
• Minimum production costs by the careful balancing of the hydrotreatment
reaction pathway (deoxygenation vs. decarboxylation)
• Minimum impact of CO/CO2 inhibition
• Fine-tuning of product cold-flow properties
• High selectivity towards desired products
• Superior stability in operation.
Advantages: For diesel production, low severity allows high cetane as well as good
cold-flow properties to meet international standards for paraffinic diesel, such as
CWA15490.
When jet fuel is targeted, depending on the feedstock, a higher severity is
applied to meet the required boiling range and freezing point, along with the other
specifications of the D7566 standard for synthetic blending component of aviation
turbine fuel, shown in the table here.
Property
Density, kg/m³
D86 T10, °C
D86 FBP, °C
Freezing point, °C
Flash point, °C
D7566
Spec.
730–770
205 max
300 max
–40 max
38 min
H2
H2
Fuel gas
MP
steam
Purge
Amine
Naphtha
Offgas
Offgas
Renewable
feed
MP
steam
DMDS
H2O
H2O
On-spec
diesel or
jet
Installations: The Vegan technology has been selected by Total for its first
bio-refinery to be located at La Mède in France. The plant will produce 500,000 tpy
of high-quality paraffinic biodiesel, treating primarily used oils and other
renewable feedstocks.
Reference:
Scharff, Y., et al., “Catalysts technology for biofuel production: Conversion of
renewable lipids into biojet and biodiesel,” Edition Diffusion Presse Sciences
(EDP Sciences), 2013.
Licensor: Axens
Website: www.axens.net/product/process-licensing/11008/vegan.html
Contact: information@axens.net
The Vegan technology’s versatility makes it possible to tailor bio-blendstocks
according to demand for diesel or jet fuel pool.
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Catalytic Cracking—
Deep Catalytic Cracking—DCC
Application: Selective conversion of gasoil and paraffinic residual feedstocks.
Products: C2–C5 olefins, aromatic-rich, high-octane gasoline and distillate.
Description: Deep catalytic cracking (DCC) is a fluidized process for selectively
cracking a wide variety of feedstocks to light olefins. Propylene yields of more than
24 wt% are achievable with paraffinic feeds. DCC uses a conventional fluid catalytic
cracking (FCC) reactor/regenerator unit design with a catalyst that has physical
properties similar to traditional FCC catalyst. The DCCU may be operated in two
modes: maximum propylene (Type 1) or maximum iso-olefins (Type 2).
Each operational mode uses unique catalyst as well as reaction conditions.
Maximum propylene DCC uses both riser and bed cracking at relatively severe
reactor conditions, while Type II DCC uses only riser cracking like a modern FCCU
at milder conditions.
The overall flow scheme of DCC is very similar to that of conventional FCC.
However, innovations in the areas of catalyst development, process variable selection,
severity and gas plant design enables the DCCU to produce significantly more olefins
than an FCCU in a maximum olefins mode of operation.
This technology is suitable for revamps as well as grassroots applications.
Integrating DCC technology into existing refineries as grassroots or revamp applications
can offer an attractive opportunity to produce large quantities of light olefins.
In a market requiring both propylene and ethylene, use of both thermal and
catalytic processes is essential due to the fundamental differences in the reaction
mechanisms involved. The combination of thermal and catalytic cracking mechanisms
is the only way to increase total olefins from light and heavy feedstocks, while meeting
the need for an increased propylene-to-ethylene ratio. A benefit associated with
DCC as opposed to steam cracking for propylene production is a direct consequence
of relative cost differences between DCC heavy feeds and a steam cracker’s light
feeds. Additional capital and operating cost savings are achieved by the integration
of the DCCU and the adjacent steam cracker.
Products, wt% of fresh feed DCC Type 1
DCC Type 2
FCC
Ethylene
6.1
2.3
0.9
Propylene
20.5
14.3
6.8
Butylene
14.3
14.6
11.0
iC4=
5.4
6.1
3.3
Amylene
–
9.8
8.5
iC5=
–
6.5
4.3
Installations: A total of 15 DCCUs have been licensed.
References:
1. Dharia, D., “Deep catalytic cracking: A commercially well-proven process
for light olefins,” Handbook of Petroleum Refining Processes, 4th Ed., Chapter 3.1,
pp. 99-113, McGraw-.Hill Professional Publishing, 2016.
2. Dharia, D., et al., “Increase light olefins production,” Hydrocarbon Processing,
pp. 61–66, April 2004.
Licensor: TechnipFMC and Research Institute of Petroleum Processing, Sinopec.
Website: www.technipfmc.com/
Contact: steve.shimoda@technipfmc.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Catalytic Cracking—FCC
Decreasing feed quality
Application: Fluid catalytic cracking (FCC) catalysts for FCC applications. Feed
applications range from very light, hydrotreated gasoil feeds to heavy residue feeds.
Product slates can be tailored to light olefins yields such as propylene, maximum
gasoline yield, or maximum distillate yield.
Gasoil
Light olefins
maximization
Description: BASF offers a full product portfolio of catalysts and additive solutions
(environmental and performance enhancing additives) that deliver value to refineries.
Maximum propylene solution (MPS)
NaphthaMax®
References:
1. Shackleford, A., “Back to basics: Maximizing octane barrels,” AFPM Q&A
and Technology Forum Conference Show Daily, Hydrocarbon Processing,
September 2016.
2. Llanes, J. M., E. Serrano, M. Arjona and B. Aramburu, CEPSA; Keeley, C., S. Riva
and V. Komvokis, BASF Corp.; and M. Miranda, BASF, “New catalyst increases
FCC Olefin Yields,” Hydrocarbon Processing, April 2014.
3. Shackleford, A., A. Garcia, S. Pan and R. Gallogly, “Improve refining of tight oil
via enhanced fluid catalytic cracking catalysts,” Hydrocarbon Processing,
September 2014.
4. Shackleford, A. and A. Garcia, “Help improve FCC profit and performance
through technical service,” AFPM Annual Meeting Conference Show Daily,
Hydrocarbon Processing, March 2014.
Defender™
Endurance®
Conversion
maximization
Borotec™
Fortress™ NXT
PetroMax™
Development/Delivery: BASF has been delivering FCC catalyst and additive
solutions to refiners since 1972.
Installations: BASF catalysts and additives have been used in more than 200
units worldwide.
Flex-Tec®
NaphthaMax® III
Yield objectives
Advantages: BASF offers the highest degree of product flexibility in terms of surface
area, zeolite/matrix ratio, metal traps and particle size distribution. With this portfolio,
refiners can take advantage of crude and market pricing to get the most out of every
barrel of oil while complying with environmental legislation. BASF provides FCC
catalyst for all ranges of operating objectives and feed quality, to tackle feeds from
very light, hydrotreated feed to the heaviest, highly contaminated resid feedstocks.
In addition, we can tailor our technology for units that have circulation concerns,
attrition sensitivity [BASF’s Low MicroFines (LMF) technology] and low-sulfur gasoline
needs (NaphthaClean).
Resid
BoroCat™
BituPro™
Distillate
maximization
HDXtra™
Aegis™
Stamina™
Licensor: BASF
Website: www.catalysts.basf.com/refining
Contact: refining-catalysts@basf.com
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2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—FCC
Application: Selective conversion of gas oil feedstocks into high-octane gasoline,
distillate and C3–C4 olefins.
Description: Catalytic and selective cracking is offered in a short contact-time
riser where oil feed is effectively dispersed and vaporized through a proprietary
feed-injection system. The operation is carried out at a temperature consistent with
targeted yields. The riser temperature profile can be optimized with the proprietary
mixed temperature control (MTC) system.
Reaction products exit the riser-reactor through a high-efficiency, close-coupled,
proprietary riser termination device, RS2TM (riser separator system). Spent catalyst
is pre-stripped, followed by an advanced high-efficiency packed stripper prior to
regeneration. The reaction product vapor may be quenched to give the lowest
possible dry gas and maximum gasoline yield. Final recovery of catalyst particles
occurs in cyclones before the product vapor is transferred to the fractionation section.
Catalyst regeneration is carried out in a single regenerator equipped with
proprietary air and catalyst distribution systems, and may be operated for either
full or partial CO combustion. Heat removal for heavier feedstocks may be
accomplished by using a reliable dense-phase catalyst cooler, which has been
commercially proven in more than 70 units. As an alternative to catalyst cooling,
this unit can easily be retrofitted to a two-regenerator system (R2R™) in the event
that a future resid operation is desired.
The converter vessels use a cold-wall design that results in minimum capital
investment and maximum mechanical reliability and safety. Reliable operation is
ensured through the use of advanced fluidization technology combined with a
proprietary reaction system. Unit design and operating conditions are tailored to
refiners’ needs (distillate, gasoline or olefins maximization) and can include wide
turndown flexibility.
Available options include power recovery, waste heat recovery, flue gas
treatment and slurry filtration. Revamps incorporating proprietary feed injection,
stripper packing, riser termination devices and vapor quench result in substantial
improvements in capacity, yields and feedstock flexibility within the mechanical
limits of the existing unit.
References:
1. Meyers, R., Handbook of Petroleum Refining Process, 3rd Ed.,
McGraw-Hill Education LLC., 1986.
Licensor: TechnipFMC and Axens license this technology.
Website: www.axens.net/product/technology-licensing/11003/fcc.html
Contact: steve.shimoda@technipfmc.com
Installations: Axens and TechnipFMC, members of the FCC Alliance, have licensed
more than 60 grassroots FCCUs and performed more than 250 revamp projects.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—
FCC Additive Technology
Application: Performance enhancing and environmental compliance additives.
Co-Catalysts have similarities with both additives and catalysts, but stand alone as
a new category of products available only from BASF Catalysts. Co-Catalysts
capture the economic advantage from changing market preferences and provide
a refiner with FCC operational flexibility, allowing them to respond in the shortest
time to rapid shifts in product values or feed change. It also allows for profitability
optimization far more quickly than reformulating the FCC catalyst.
Description:
Performance additives
• ZIP—Octane and olefins enhancement
• USP/Procat—CO promotion
• LSA—Gasoline sulfur reduction
• EZ Flow—Flow-aid.
Environmental additives
• CLEANOx—NOx reduction
• EnviroSOx—SOx reduction
• CONQUERNOX—Low-NOx CO promoter.
Co-Catalysts
• Converter—Conversion enhancement catalyst
• HDUltra—Distillate.
Advantages:
• Excellent reductions of NOx and SOx emissions
• Increased LPG olefins yields and gasoline octane enhancement
• Conversion enhancement
• Fluidization aid
• Sulfur reduction in the gasoline cut
• High performance CO promotion using platinum
• CO promotion using palladium for low NOx formation.
Development/Delivery: BASF has been delivering FCC catalyst and additive
solutions to refiners since 1972.
Installations: BASF catalysts and additives have been used in more than 200
units worldwide.
Reactor effluent to fractionator
Cyclone vessel
Flue gas
Stripper
Stripping steam
Catalyst
regenerator
Stripper
standpipe
Riser reactor
Air
Regenerator
standpipe
Air heater
Lower feed injection
Fresh feed
Dispersion steam
References:
4. Clough, M., “We can sulfur problems: Catalyst solutions to meet
Tier 3 regulations,” AFPM Annual Meeting Conference Show Daily,
Hydrocarbon Processing, March 2017.
Licensor: BASF
Website: www.catalysts.basf.com/refining
Contact: refining-catalysts@basf.com
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Catalytic Cracking—FCC-MIP
Application: SINOPEC’s FCC-maximizing isoparaffin (MIP) process is characterized
by a novel, sequential two-zone riser that converts heavy oil into low-olefin and
low-sulfur gasoline. As a novel fluid catalytic cracking (FCC) technology, it can be
applied for the conventional FCC revamp or grassroots project.
Description: SINOPEC’s FCC-MIP process flow is similar to a conventional FCCU,
but with a novel two-zone riser. The MIP riser’s 1st zone is similar to a conventional
FCCU. The cracking reactions mainly happen here, while the riser’s 2nd zone diameter
is enlarged, and the catalysts are quenched by the cold agent. The resulting high
residence time (approximately 5 sec), and relative low-reaction temperature, benefits
the conversion of olefins to isoparaffin, etc.
Advantages: The advances of SINOPEC’s FCC-MIP process include:
• Operating flexibility: Based on product demands, the MIP technology provides
operators with the flexibility to switch among different operation modes.
• Feed adaptability: The MIP process has been developed into a platform
technology that enables the operator to process various feeds, including
VGO, CGO, AR, VR, HVGO, RDS and DAO, etc.
• Performance index: The olefin content in MIP naphtha can be adjusted between
17 vol%–35 vol%. Compared to a conventional FCC process, the MIP process
produces more FCC naphtha and less dry gas and slurry, along with increases
in total liquid yields. MIP technology can reduce sulfur content in gasoline by
20%–40%, and increase isobutane in liquefied petroleum gas (LPG) by 40%.
• Onstream time: The onstream time for MIP units is the same as that of
conventional FCCUs (i.e., 4 yr–5 yr).
Installations: A total of 52 MIP units have been installed, with a combined capacity
of 83.14 MMtpy. The largest single unit has a capacity of 3.5 MMtpy.
References:
1. Long, J., Y. Xu and J. Zhang, et al., “Consider new process for clean gasoline
and olefins production,” Hydrocarbon Processing, September 2011.
2. Gong, J. and Y. Xu, et al., “Development of MIP technology and its proprietary
catalysts,” China Petroleum Processing and Petrochemical Technology,
No. 2, June 2009.
3. Akah, A. and M. Al-Ghrami, “Maximizing propylene production via FCC
technology,” Applied Petrochemical Research, Vol. 5, pp. 377–392, 2015.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
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2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—FCC pretreatment
Application: Haldor Topsoe’s FCC pretreatment technology is designed to treat a wide
variety of feedstocks ranging from gas oils through heavy-vacuum gas oils and coker
streams to resids. This pretreatment process can maximize FCC unit performance.
Makeup hydrogen
Objectives: The processing objectives range from deep desulfurization for meeting
gasoline-sulfur specifications from the FCC products, to denitrogenation and
metals removal, thus maximizing FCC catalyst activity. Additional objectives
can include Conradson carbon reduction and saturation of polyaromatics
to maximize gasoline yields.
Description: The Topsoe FCC pretreatment technology combines understanding
of kinetics, high-activity catalysts, state-of-the-art internals and engineering skills.
The unit can be designed to meet specific processing objectives in a cost-effective
manner by utilizing the combination of processing severity and catalyst activity.
Topsoe has experience in revamping moderate- to low-pressure units for deep
desulfurization. Such efforts enable refiners to directly blend gasoline produced
from the FCC and meet low-sulfur (less than 15 ppm) gasoline specifications.
An additional option is Topsoe’s Aroshift process that maximizes the conversion
of polyaromatics, which can be equilibrium limited at high operating temperatures.
The Aroshift process increases the FCC conversion, and the yield of gasoline and
C3 /C4 olefins, while reducing the amount of light- and heavy-cycle oil. Furthermore,
the quality of the FCC gasoline is improved. Topsoe has a wide variety of catalysts
for FCC pretreatment service. The catalyst types cover TK-560 BRIM and TK-562 BRIM,
a CoMo catalyst with high desulfurization activity, and TK-561 BRIM, a NiMo catalyst
with hydrodesulfurization and high hydrodenitrogenation activity. Topsoe offers a
wide range of engineering scopes from full scoping studies, reactor design packages
and process design packages to engineering design packages.
Operating conditions: Typical operating pressures range from 60 bar–125 bar
(900 psi–1,800 psi), and temperatures from 300°C–430°C (575°F–800°F).
Installations: 10 units.
Recycle gas
compressor
Furnace
Absorber
Lean amine
Reactor
Rich amine
H2 rich gas
Fresh feed
Products to
FCC or fractionation
High-pressure
separator
Low-pressure
separator
3. Patel, R., P. Zeuthen and M. Schaldemose, “Advanced FCC feed pretreatment
technology and catalysts improves FCC profitability,” NPRA Annual Meeting,
San Antonio, March 2002.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/products/fluid-catalytic-cracking-fcc-pretreatment
Contact: mkj@topsoe.com
References:
1. Andonov, G., S. Petrov, D. Stratiev and P. Zeuthen, “MCHC mode vs. HDS mode
in an FCC unit in relation to Euro IV fuels specifications,” 10th ERTC, Vienna,
November 2005. Patel R., H. Moore and B. Hamari,
2. “FCC hydrotreater revamp for low-sulfur gasoline,” NPRA Annual Meeting, San
Antonio, March 2004.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—
FCC Technology Platform Options
Application: BASF’s FCC catalyst portfolio is based on three technology platforms:
DMS, ProxSMX and BBT.
Description:
DMS provides porosity for heavy molecule diffusion and cracking. Pre-cracking
is done with the selective external zeolite surface, rather than an amorphous
non-selective matrix. The combination of the matrix and zeolite technologies
allows for high activity and coke selectivity. Features include:
• For high conversion, gasoline and LPG olefins
• High-activity zeolite
• Improved hydrothermal stability leading to higher unit activity
• Coke selective cracking
• Successful operation in > 150 commercial FCCUs
• Products: Naphthamax, Naphthamax III, NaphthaClean, Low Sulphur Additive,
Flex-Tec, MPS, Converter, Defender, Bitupro and more.
Prox-SMX catalysts are based on BASF’s low zeolite-to-matrix platform. They
have optimized porosity to improve diffusion of heavy feed and iron tolerance. Zeolite
and matrix are formed in a single step. Close proximity of zeolite and matrix maximizes
bottoms upgrading. Lowest sodium content minimizes hydrogen transfer, as well as
better light cycle oil (LCO) cetane and better vanadium tolerance. Features include:
• Maximizing distillate yield
• Highly stable and coke selective matrix for bottoms conversion to LCO
• Proximal structure—zeolite and active matrix are created in a single process
step and are intimately dispersed
• Ultra-low sodium for max stability and minimal hydrogen-transfer
• Products: HDXtra, HDUltra, Stamina, Aegis (combination of Prox-SMZ + DMS).
BBT utilizes a novel chemistry for improved nickel passivation versus today’s
technologies; essentially, boron migrates within the catalyst by solid-state diffusion to
passivate nickel (Ni). The boron prevents nickel from being detrimentally reduced in the
FCC riser. Performance benefits include a reduction in hydrogen and delta coke.
• For contaminated feedstocks, especially high nickel, and can be tailored toward
maximum distillate and/or conversion
• Utilizes the novel chemistry of boron
• For the dirtiest of feeds with high contaminants, especially nickel
• Provides deep bottoms conversion to valuable liquid products
• Products: BoroCat, Borotec.
Reactor effluent to fractionator
Cyclone vessel
Flue gas
Stripper
Stripping steam
Catalyst
regenerator
Stripper
standpipe
Riser reactor
Air
Regenerator
standpipe
Air heater
Lower feed injection
Fresh feed
Dispersion steam
Development/Delivery: The award-winning Distributed Matrix Structures™ (DMS),
Proximal Stable Matrix & Zeolite (Prox-SMZ), plus our newly developed Boron Based
Technology (BBT) platforms form the foundation of our innovative FCC products.
Installations: BASF catalysts and additives have been used in more than 200
units worldwide.
Licensor: BASF
Website: www.catalysts.basf.com/refining
Contact: refining-catalysts@basf.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Catalytic Cracking—Fluid catalytic
cracking
Application: Selective and high conversion of a wide range of feedstocks into
high-value products. Feedstocks include virgin or hydrotreated gasoils that may
also include lube oil extract, coker gasoil, solvent de-asphalting and heavy residues.
Products: High-octane gasoline, light olefins and distillate. Flexibility in unit
operation allows for maximizing the most desirable product.
Description: The Lummus process incorporates an advanced reaction system,
high-efficiency catalyst stripper and a mechanically robust, single-stage full burn
regenerator. Oil is injected into the base of the riser via proprietary Micro-Jet™ feed
injection nozzles (1). Catalyst and oil vapor flow upwards through a short-contact time,
all-vertical riser (2) where raw oil feedstock is cracked under optimum conditions.
Reaction products exiting the riser are separated from the spent catalyst in a
patented, direct-coupled cyclone system (3). Product vapors are routed directly to
fractionation, thereby eliminating nonselective post-riser cracking reactions and
maintaining the optimum product yield slate. Spent catalyst containing only minute
quantities of hydrocarbon is discharged from the diplegs of the direct-coupled
cyclones into the cyclone containment vessel (4). The catalyst flows down into the
stripper containing proprietary ModGrid® internals (5).
Trace hydrocarbons entrained with spent catalyst are removed in the
ModGrid stripper using stripping steam. The ModGrid stripper efficiently removes
hydrocarbons at a lower steam rate than other FCC strippers. The net stripper
vapors are routed to the fractionator via specially designed vents in the directcoupled cyclones. Catalyst from the stripper flows down the spent catalyst standpipe
and through the slide valve (6). The spent catalyst is then transported in dilute phase
to the center of the regenerator (8) through a unique square-bend-spent catalyst
transfer line (7). This arrangement provides the lowest overall unit elevation.
Catalyst is regenerated by efficient contacting with air for complete combustion
of coke. For resid-containing feeds, a catalyst cooler is integrated with the
regenerator. The resulting flue gas exits via cyclones (9) to energy recovery/flue gas
treating. The hot regenerated catalyst is withdrawn via an external withdrawal
well (10). The well allows independent optimization of catalyst density in the
regenerated catalyst standpipe, maximizes slide valve (11) pressure drop and
ensures stable catalyst flows back to the riser feed injection zone.
The catalyst formulation can be tailored to maximize the most desired product.
Installation: Sixty-two licensed units.
Licensor: Lummus Technology, a CB&I company
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Catalytic Cracking—Fluid Catalytic
Cracking (FCC)
Application: Selective conversion of gasoil feedstocks into high-octane gasoline,
distillate and C3–C4 olefins.
Description: Catalytic and selective cracking in a short-contact-time riser where
oil feed is effectively dispersed and vaporized through a proprietary feed-injection
system. The operation is carried out at a temperature consistent with targeted
yields. The riser temperature profile can be optimized with the proprietary mixed
temperature control (MTC) system.
Reaction products exit the riser-reactor through a high-efficiency, close-coupled,
proprietary riser termination device RSS (riser separator system). Spent catalyst
is pre-stripped, followed by an advanced high-efficiency packed stripper prior to
regeneration. The reaction product vapor may be quenched to give the lowest
possible dry gas and maximum gasoline yield. Final recovery of catalyst particles
occurs in cyclones before the product vapor is transferred to the fractionation section.
Catalyst regeneration is carried out in a single regenerator equipped with
proprietary air and catalyst distribution systems, and may be operated for either full
or partial carbon monoxide (CO) combustion. Heat removal for heavier feedstocks
may be accomplished by using a reliable dense-phase catalyst cooler, which has been
commercially proven in more than 65 units. As an alternative to catalyst cooling,
this unit can easily be retrofitted to a two-regenerator system (R2R) in the event
that a future resid operation is desired.
The converter vessels use a cold-wall design that results in minimum CAPEX and
maximum mechanical reliability and safety. Reliable operation is ensured through the
use of advanced fluidization technology combined with a proprietary reaction system.
Unit design is tailored to the refiner’s needs and can include wide turndown flexibility.
Available options include power recovery, waste-heat recovery, flue gas treatment
and slurry filtration. Revamps incorporating proprietary feed injection and riser
termination devices, and vapor quench result in substantial improvements in capacity,
yields and feedstock flexibility within the mechanical limits of the existing unit.
References:
1. Meyers, R., Handbook of Petroleum Refining Process, 3rd Ed., McGraw-Hill, 2004.
Licensor: Axens.
Website: www.axens.net/product/technology-licensing/11003/fcc.html
Contact: www.axens.net/contact.html
Installations: Axens have licensed 50 grassroots FCCUs and performed more than
200 revamp projects.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Catalytic Cracking—
Fluidized catalytic cracking
To fractionator
Close
coupled
cyclones
Application: The Shell fluidized catalytic cracking (FCC) process converts heavy
distillates and residues into high-value products, and includes selective propylene
production when required.
Description: In this process, Shell’s erosion-resistant feed nozzle system delivers
atomized hydrocarbons to a short-contact-time riser. This design ensures good
mixing and rapid vaporization into the hot catalyst stream throughout the run.
Cracking selectivity is enhanced by the feed nozzles and proprietary riser internals,
which lessen catalyst back-mixing while reducing the overall riser pressure drop.
The riser termination design incorporates reliable close-coupled cyclones that
provide rapid catalyst–hydrocarbon separation. The design minimizes post-riser
cracking and maximizes desired product yields. Efficient catalyst stripping is ensured
by the application of robust, high-capacity, proprietary PentaFlow baffles.
A single-stage partial- or full-burn regenerator delivers excellent performance
at a low cost. Proprietary internals are used at the catalyst inlet to disperse the
catalyst, and at the catalyst outlet to provide significant catalyst circulation
capacity. Catalyst coolers can be added for more feedstock flexibility.
Cyclone systems in the reactor and the regenerator use a proprietary design that
provides reliability, efficiency and robustness. Flue gas particulate removal can be
achieved with Shell’s third-stage separator with its proprietary swirl vanes.
Shell’s FCC process model, Shell advanced and rigorous catalytic cracking
(SHARC®), is available for accurate simulation and unit performance monitoring
and optimization. SHARC process models can also be incorporated into refinery
planning tools.
Shell FCC technologies have proven reliability, owing to the simplicity of their
components and the incorporation of Shell’s extensive operating experience.
Installation: More than 30 grassroots units have been designed or licensed, including
seven to handle residue feeds, and more than 60 units that have been revamped.
References:
1. Ludolph, R., D. Hunt, J. Van Roeyen and K. Kunz, “Performance assessment
of feed nozzle upgrades,” AFPM Annual Meeting, San Antonio, Texas, 2017.
2. Hunt, D., S. Chatterjee, B. Munsch and R. Sanborn, “Implementation of state-ofthe-art FCC technology for improved reliability and profitability at Deer Park
refinery,” AFPM Annual Meeting, Orlando, Florida, 2014.
To heat recovery
Proprietary reactor
and regenerator
cyclone system
Efficent
stripping
Catalyst
circulation
enhancement
technology
Advanced
spent catalyst
inlet device
Riser
internals
Highperformance
feed nozzles
Thrid-stage
separator
Catalyst fines
Cold-wall
construction
3. Chatterjee, S., C. Carroll, M. Basden, C. Burton, S. Nelson and K. Kunz, “SHARC
and CFD assess and validate Shell Puget Sound’s profitable reliability,”
AFPM Annual Meeting, San Antonio, Texas, 2015.
4. Chen, Y. -M., et al., “Keeping FCC units on track: Winning the operation race
with an innovative cyclone technology,” AFPM Annual Meeting, Phoenix,
Arizona, 2010.
5. Chen, Y. -M., “Shell third-stage separator technology: Evolution and recent
advances in third-stage separator technology for applications in the
FCC process,” AFPM Annual Meeting, Salt Lake City, Utah, 2006.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—High Severity—
HS-FCC™
Application: Selective conversion of gasoil and heavy residual feedstocks into
high-octane gasoline and C3–C4 olefins.
Description: An alliance comprising Saudi Aramco, JX Nippon Oil & Energy Corp. (JX),
King Fahad University of Petroleum and Minerals, and Axens/TechnipFMC, has developed
the HS-FCC process, which is able to produce up to 25% of propylene by converting
heavy hydrocarbon feedstock under severe FCC conditions, using a novel downflow
reactor concept. A 3,000-bpsd, HS-FCC semi-commercial plant started in 2011 at the
JX Group’s Mizushima refinery in Japan. In addition to propylene, considerable amounts
of butenes, gasoline and aromatics are produced as valuable byproducts. The HS-FCC
product portfolio can be further increased toward propylene and aromatics by further
downstream conversion of its less desired products, using proven technology approaches.
The main features of the HS-FCC process comprise a downflow reactor, high-reaction
temperature, short contact time and high catalyst-to-oil (C/O) ratio. Operating the HSFCC process at high temperature and high C/O ratio results in two competing cracking
reactions: thermal cracking and catalytic cracking. Thermal cracking contributes to dry gas
production, while catalytic cracking contributes to enhancing propylene yield of propylene.
A downflow reactor system has been adopted. The catalyst and the feed flow
downward (with gravity) to minimize back mixing in the reactor and to obtain a narrower
distribution of residence time that allows maximizing intermediate products, such as
gasoline and light olefins. The downflow reactor allows a higher C/O ratio because the
lifting of catalyst by vaporized feed is not required. The downflow reaction ensures plug
flow without back mixing.
The HS-FCC process is operated under considerably higher reaction temperatures
(550°C–650°C) than conventional FCCUs. Under these reaction temperatures, thermal
cracking of hydrocarbons also takes place concurrently with catalytic cracking, resulting
in increased undesirable byproducts as dry gas and coke. The short contact time (less
than 0.5 sec) of feed and product hydrocarbons in the downer minimizes thermal
cracking. Undesirable successive reactions such as hydrogen transfer, which consumes
olefins, are suppressed.
To attain short residence time, the catalyst and products must be separated
immediately at the reactor outlet. For this purpose, a high-efficiency, short-residence
time product separator was developed and is capable of suppressing side reactions
(oligomerization and hydrogenation of light olefins), as well as coke formation.
To compensate for a drop in conversion due to short contact time, the HS-FCC
process is operated at a high C/O ratio. Under the high C/O ratio, there is the enhanced
contribution of catalytic cracking over thermal cracking. High C/O maintains heat balance
and helps minimize thermal cracking, over-cracking and hydrogen transfer reactions.
Development/Delivery: The highly selective HS-FCC process has been developed
through an alliance comprising Saudi Aramco, JX Nippon Oil & Energy Corp. (JX),
King Fahd University of Petroleum and Minerals, TechnipFMC and Axens.
Installations: One 3,000-bpsd unit in Japan.
References:
1. ERTC Annual Meeting, 2010, Istanbul, Turkey.
Licensor: Axens
Website: www.axens.net/product/technology-licensing/11004/
hs-fcc-high-severity-fcc.html
Contact: www.axens.net/contact.html
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—
High Severity HS-FCC™
Application: Selective conversion of gasoil and heavy residual feedstocks into highoctane gasoline and C3–C4 olefins.
Description: An alliance comprising Saudi Aramco, JX Nippon Oil & Energy Corp.
(JX), King Fahad University of Petroleum and Minerals, and Axens/TechnipFMC, has
developed the HS-FCCTM process, which is able to produce up to 25% of propylene
by converting heavy hydrocarbon feedstock under severe FCC conditions, using
a novel downflow reactor concept. A 3,000-bpsd HS-FCC semi-commercial plant
operated at the JX group’s Mizushima refinery in Japan from 2011–2014. In addition
to propylene, a considerable amount of butenes, gasoline and aromatics are
produced as valuable byproducts. The HS-FCC product portfolio can be further
increased toward propylene and aromatics by further downstream conversion
of its less desired products, using proven technology approaches.
The main features of the HS-FCC process include a downflow reactor, highreaction temperature, short contact time and high catalyst-to-oil (C/O) ratio.
Operating the HS-FCC process at high temperature and high C/O ratio results in
two competing cracking reactions: thermal cracking and catalytic cracking.
Thermal cracking contributes to dry gas production, while catalytic cracking
contributes to enhancing propylene yield.
For HSFCC, a downflow reactor system has been adopted. The catalyst and the
feed flow downward with gravity, minimizing back mixing in the reactor and allowing
a shorter residence time that maximizes intermediate products such as gasoline
and light olefins, while minimizing over-cracking. The downflow reactor allows
a higher C/O ratio because the lifting of catalyst by vaporized feed is not required.
The downflow reaction ensures plug flow without back mixing.
The HS-FCC process is operated under considerably higher reaction
temperatures (550°C–650°C) than conventional FCCUs. Under these reaction
temperatures, however, thermal cracking of hydrocarbons normally takes place
concurrently with catalytic cracking, resulting in increased undesirable byproducts
such as dry gas and coke. Short contact time (around 0.5 sec) of feed and product
hydrocarbons in the downflow reactor minimizes thermal cracking. Undesirable
successive reactions—such as hydrogen (H2 ) transfer, which consumes olefins—
are suppressed.
To attain short residence time, the catalyst and products must be separated
immediately at the reactor outlet. For this purpose, a high-efficiency, short-residence
time product separator, Tempest™, was developed and is capable of suppressing
side reactions (oligomerization and hydrogenation of light olefins) along with
coke formation.
To compensate for a drop in conversion due to short contact time, the
HS-FCC process is operated at a high C/O ratio. Under the high C/O ratio, there is
the enhanced contribution of catalytic cracking over thermal cracking. A high C/O
ratio maintains heat balance and helps minimize thermal cracking, over cracking
and H2 transfer reactions.
Development/Delivery: The highly selective HS-FCC process has been developed
through an alliance comprised of Saudi Aramco, JX Nippon Oil & Energy Corp. (JX),
King Fahd University of Petroleum and Minerals, TechnipFMC and Axens.
Continued 
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Catalytic Cracking—High Severity HS-FCC™ (cont.)
Installations: Three licenses, including the 3,000-bpsd unit in Japan.
References:
1 ERTC Annual Meeting, 2010, Istanbul, Turkey.
Licensor: TechnipFMC and Axens license this technology
Website: www.axens.net/product/technology-licensing/11004/
hs-fcc-high-severity-fcc.html
Contact: Eusebrius.gbordzue@technipfmc.com
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Catalytic Cracking—Indmax℠ FCC
for maximum olefins
Application: The Indmax fluid catalytic cracking (FCC) process converts heavy oils—
such as heavy vacuum gasoil (HVGO) and a variety of heavy residue oils (virgin and
treated atmospheric tower bottoms and vacuum tower bottoms, heavy coker fuel
oils, lube extracts, solvent de-asphalting oils, etc.)—into light olefins and high-octane
gasoline. Similar to a crude distillation unit (CDU) in a refinery, the Indmax FCC process
is like a mother unit to a petrochemicals complex, providing a strong linkage between
refinery and petrochemical plants integration. Each molecule produced from Indmax
FCC has the potential for use as raw material for petrochemical building blocks.
Products: Light olefins such as propylene, ethylene and butylenes, high-octane
gasoline, alkylation feed and BTX (benzene, toluene and mixed xylenes)-rich
naphtha. The Indmax FCC process is highly flexible, as it involves only riser cracking.
The operation can be easily adjusted depending on the demand and pricing of
different products, e.g., from propylene mode to gasoline mode, or vice-versa.
Catalyst: The Indmax catalyst is a unique, proprietary and multi-functional
catalyst formulation that promotes selective catalytic cracking to provide very
high conversion and yield of light olefins. It is highly metals-tolerant and produces
lower coke and dry gas yield that are particularly important when processing heavy
residue to make light olefins. The catalyst formulation can be customized to meet
any changes in feedstock properties or market demand of the various products.
Indmax catalyst also overcomes the drawbacks of ZSM-5, such as over-cracking
of gasoline and dilution effects that might lead to conversion loss.
Description: The Indmax FCC process combines the proprietary Indmax catalyst
and process concepts developed by Indian Oil Corp. Ltd.’s R&D Centre (IOCL R&D)
in India, with the state-of-the-art FCC technology/design features and know-how
of Lummus Technology, now CB&I. CB&I is the exclusive licensor of Indmax FCC
technology worldwide.
The synergistic features of Indmax catalyst and hardware immensely reduce
delta coke that reduces regenerator temperature and increases catalyst-to-oil ratio
and conversion. These features enhance the ability to process heavier feeds without
a carbon monoxide (CO) boiler, catalyst cooler and feed furnace.
The Indmax FCCU is designed for and operated at Indmax process conditions:
a riser reactor temperature between 560°C and 600°C, a catalyst-to-oil ratio from
12–20, and lower hydrocarbon partial pressure compared to conventional FCC
operations. The Indmax FCC process incorporates an advanced reaction system,
high-efficiency catalyst stripper and a mechanically robust, single-stage full burn
regenerator. Oil is injected into the base of the riser via proprietary Micro-Jet™
feed injection nozzles (1). Catalyst and oil vapor flow upwards through a shortcontact time, all-vertical riser (2) where raw oil feedstock is cracked under optimum
conditions. Reaction products exiting the riser are separated from the spent catalyst
in a patented, direct-coupled cyclone system (3). Product vapors are routed directly
to fractionation, thereby eliminating nonselective, post-riser cracking and maintaining
the optimum product yield slate. Spent catalyst containing only minute quantities
of hydrocarbon is discharged from the diplegs of the direct-coupled cyclones into
the cyclone containment vessel (4). The catalyst flows down into the stripper
containing proprietary ModGrid® internals (5). The hydrocarbons entrained
with spent catalyst are removed in the ModGrid stripper using stripping steam.
The ModGrid stripper efficiently removes hydrocarbons at a lower steam rate than
other FCC strippers. The net stripper vapors are routed to the fractionator via
specially designed vents in the direct-coupled cyclones. Catalyst from the stripper
Continued 
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Catalytic Cracking—Indmax℠ FCC for maximum olefins (cont.)
flows down the spent catalyst standpipe and through the slide valve (6). The spent
catalyst is then transported in dilute phase to the center of the regenerator (8)
through a unique square-bend spent catalyst transfer line (7). Catalyst is regenerated
by efficient contacting with air for complete combustion of coke. For resid-containing
feeds, an optional catalyst cooler is integrated with the regenerator. The resulting flue
gas exits via cyclones (9) to energy recovery/flue gas treating. The hot regenerated
catalyst is withdrawn via an external withdrawal well (10). The well allows
independent optimization of catalyst density in the regenerated catalyst standpipe,
maximizes slide valve (11) pressure drop and ensures stable catalyst flow back to the
riser feed injection zone.
Installation: Total of four Indmax FCCUs are licensed. Two commercial units are
in operation and two more Indmax RFCCUs are at detail engineering phases
of design that will maximize propylene from heavy residue feed stocks.
Licensor: Lummus Technology, a CB&I company
Website: www.cbi.com
Contact: lummus.tech@cbi.com
2017 REFINING PROCESSES HANDBOOK
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Catalytic Cracking—Orthoflow,
ATOMAX™
Application: Conversion of gasoils and residues to light olefins, high-octane gasoline
and distillates using the compact, self-supporting Orthoflow converter.
Description: Feed enters through the proprietary ATOMAX feed injection system.
Reaction vapors progress up the riser, pass through a right angle turn and are quickly
separated from the catalyst in a closed-cyclone system. Cyclones are the market
leader in riser termination, and they minimize dry-gas make and increase: gasoline
yield. Spent catalyst flows through a stripper equipped with either packing or
Dynaflux baffles to the regenerator, where counter-current flow of catalyst and air
contacting is carried out.
Catalyst flow from the regenerator to the external vertical riser is controlled by
the riser outlet temperature, which regulates the regenerated catalyst slide valve. A
plug valve, located in the regenerator bottom head, controls the level in the stripper by
regulating the catalyst flow from the spent catalyst standpipe.
Either partial or complete carbon monoxide (CO) combustion may be used in the
regenerator. Flue gas flows to an external plenum and then to the flue-gas system. A
CycloFines™ third-stage separator may be used to remove particulates from the flue
gas for protection of a power recovery expander and/or compliance with particulate
emissions standards. Emissions can be further reduced with the use of RegenMax™
packing in the regenerator.
Advantages: The converter is a one-piece modularized unit that combines the
disengager, stripper and regenerator vessels into a single structure. This unique design
minimizes the cost of construction, and reduces the amount of field mechanical work
and required plot space.
Installations: KBR has licensed nearly 60 units, with a combined capacity of almost
1.4 MMbpd.
References:
• Leigh D. R., Pillai, R. and Tragesser, S., “Revamping Holly Frontier El Dorado FCC,”
Petrotech 2016, New Delhi, December 2016.
• “Maximizing flexibility for FCC’s designed to maximize propylene,”
NPRA Annual Meeting, March 9–11, 2008, San Diego, California.
• Gbordzoe, E, S. Lang and P. K. Niccum, “Optimize FCC flue-gas emission
control—Part 2,” Hydrocarbon Processing, October 2002.
• “New developments in FCC feed injection and stripping technologies,”
NPRA Annual Meeting, San Francisco, California, March 2000.
• Miller, R. B., Johnson, T. E., “RegenMax Technology: Straged Combustion
in a Single Regenerator,” NPRA 1999.
Licensor: KBR Inc.
Contact: technologyconsulting@kbr.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Catalytic Cracking—R2R™
Application: Selective conversion of gasoil and heavy residual feedstocks into highoctane gasoline, distillate and C3–C4 olefins.
Description: For residue cracking, the process is known as R2R (reactor–2
regenerators). Catalytic and selective cracking occurs in a short contact-time riser
where oil feed is effectively dispersed and vaporized through a proprietary feedinjection system. Operation is carried out at a temperature consistent with targeted
yields. The riser temperature profile can be optimized with the proprietary mixed
temperature control (MTC) system.
Reaction products exit the riser-reactor through a high-efficiency, close-coupled,
proprietary riser termination device RSS (riser separator system). Spent catalyst
is pre-stripped followed by an advanced high efficiency packed stripper prior to
regeneration. The reaction product vapor may be quenched to give the lowest dry gas
and maximum gasoline yield. Final recovery of catalyst particles occurs in cyclones
before the product vapor is transferred to the fractionation section.
Catalyst regeneration is carried out in two independent stages equipped with
proprietary air and catalyst distribution systems, resulting in fully regenerated catalyst
with minimum hydrothermal deactivation, plus superior metals tolerance relative
to single-stage systems. These benefits are derived by operating the first-stage
regenerator in a partial burn mode, the second-stage regenerator in a full-combustion
mode, and both regenerators in parallel with respect to air and flue gas flows.
The resulting system is capable of processing feeds up to about 6 wt% Conradson
carbon residue (CCR) without additional catalyst cooling means, with less air, lower
catalyst deactivation and smaller regenerators than a single-stage regenerator design.
Heat removal for heavier feedstocks—above 6 CCR—may be accomplished by using
a reliable dense-phase catalyst cooler, which has been commercially proven in more
than 65 units.
The converter vessels use a cold-wall design that results in minimum CAPEX and
maximum mechanical reliability and safety. Reliable operation is ensured through the
use of advanced fluidization technology combined with a proprietary reaction system.
Unit design is tailored to refiner’s needs and can include wide turndown flexibility.
Available options include power recovery, waste-heat recovery, flue-gas treatment and
slurry filtration.
Existing gasoil units can be easily retrofitted to this technology. Revamps
incorporating proprietary feed injection, riser termination devices and vapor quench
result in substantial improvements in capacity, yields and feedstock flexibility within
the mechanical limits of the existing unit.
Installations: Shaw and Axens have licensed 50 grassroots FCCUs and performed
more than 200 revamp projects.
References:
1. Meyers, R., Handbook of Petroleum Refining Process, 3rd Ed., McGraw-Hill, 2004.
Licensor: Axens and TechnipFMC.
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/21/
catalytic-cracking---rfcc.html
Contact: www.axens.net/contact.html
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Catalytic Cracking—Resid R2R™
Application: Selective conversion of gasoil and heavy residual feedstocks into
high-octane gasoline, distillate and C3–C4 olefins.
Description: For residue cracking, the process is called R2R (reactor–2 regenerators).
Catalytic and selective cracking occurs in a short contact-time riser, where oil feed
is effectively dispersed and vaporized through a proprietary feed injection system.
Operation is carried out at a temperature consistent with targeted yields. The riser
temperature profile can be optimized with the proprietary mixed temperature
control (MTC) system.
Reaction products exit the riser-reactor through a high-efficiency, close-coupled,
proprietary riser termination device – RS2 (riser separator system). Spent catalyst
is pre-stripped, followed by an advanced high-efficiency packed stripper prior to
regeneration. The reaction product vapor may be quenched to give the lowest dry
gas and maximum gasoline yield. Final recovery of catalyst particles occurs in
cyclones before the product vapor is transferred to the fractionation section.
Catalyst regeneration is carried out in two independent stages that are equipped
with proprietary air and catalyst distribution systems, resulting in fully regenerated
catalyst with minimum hydrothermal deactivation, as well as superior metals tolerance
relative to single-stage systems. These benefits are derived by operating the first-stage
regenerator in a partial burn mode, the second-stage regenerator in a full-combustion
mode and both regenerators in parallel with respect to air and flue gas flows.
The resulting system is capable of processing feeds up to approximately 6 wt%
Conradson carbon residue (CCR) without additional catalyst cooling, with less air,
lower catalyst deactivation and smaller regenerators than a single-stage regenerator
design.
Heat removal for heavier feedstocks (above 6 CCR) may be accomplished
by using a reliable dense-phase catalyst cooler, which has been commercially proven
in more than 70 units.
The converter vessels use a cold-wall design that results in minimum capital
investment and maximum mechanical reliability and safety.
Reliable operation is ensured through the use of advanced fluidization technology
combined with a proprietary reaction system. Unit design is tailored to refiners’ needs
and can include wide turndown flexibility. Available options include power recovery,
waste heat recovery, flue-gas treatment and slurry filtration.
Existing gasoil units can be retrofitted to this technology. Revamps incorporating
proprietary feed injection and riser termination devices and vapor quench result
in substantial improvements in capacity, yields and feedstock flexibility within the
mechanical limits of the existing unit.
Installations: TechnipFMC and Axens, members of the FCC Alliance, have licensed
more than 60 grassroots fluid catalytic cracking units (FCCUs) and performed
more than 250 revamp projects.
References:
1. Meyers, R., Handbook of Petroleum Refining Process, 3rd Ed.,
McGraw-Hill Education LLC., 1986.
Licensor: TechnipFMC and Axens license this technology.
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/
21/catalytic-cracking---rfcc.html
Contact: steve.shimoda@technipfmc.com
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Catalytic Cracking—
Resid to Propylene—R2P™
Application: Selective conversion of heavy feedstocks into petrochemical products
into C3–C4 olefins—particularly propylene—high-octane gasoline and aromatics.
Description: Based on the R2R resid fluid catalytic cracking (RFCC) process using a
riser and a double regenerator for gasoline production, this new petrochemical version
is oriented toward light olefins—particularly propylene—and aromatics. The process is
characterized by the utilization of two independent risers. The main riser cracks the resid
feed under conditions to optimize fuels production; and the second PetroRiser riser is
operated to selectively crack specific recycle streams to maximize propylene production.
The RFCC process applies a short contact-time riser, proprietary injection
system and severe cracking conditions for bottoms conversion. The temperature
and catalyst circulation rates are higher than those used for a conventional gasoline
mode operation. The main riser temperature profile can be optimized with a mixed
temperature control (MTC) system.
Reaction products are then rapidly separated from the catalyst through a highefficiency riser termination device (RS2 ). Recycle feed is re-cracked in the PetroRiser
under conditions that are substantially more severe than in the main riser. A precise
selection of recycle cuts combined with adapted commercial FCC catalysts and
additives lead to high propylene yields with moderate dry-gas production.
Both the main riser and PetroRiser are equipped with a rapid separation system,
and the deactivated catalysts are collected into a single packed stripper, which
enhances the steam stripping efficiency of the catalyst.
Catalyst regeneration is carried out in two independent stages to minimize
permanent hydrothermal activity loss. The first stage is operated in a mild partialcombustion mode that removes produced moisture and limits catalyst deactivation,
while the second stage finishes the combustion at higher temperature to fully restore
catalyst activity. The R2R system can process residue feed containing high metals and
conradson carbon residue (CCR) using this regenerator configuration, and even higher
contents with the addition of a catalyst cooler.
The recycle feeds that can be used in the PetroRiser are light and medium FCC
gasoline, as well as olefin streams coming from a butenes oligomerization unit. This
last option is particularly interesting under market conditions that favor propylene over
C4 olefins. The reaction and regeneration sections use a cold-wall design that results
in minimum CAPEX and maximum mechanical reliability and safety. Units are tailored
to fit market needs (feedstock and product slate) and can include a wide range of
turndown flexibility. Available options include power recovery, waste-heat recovery,
flue-gas treatment and slurry filtration, and light olefins recovery and purification.
Installations: PetroRiser technology is available for revamp of all RFCC and
FCC units. Axens and TechnipFMC have licensed more than 50 FCCUs and performed
more than 200 revamp projects since the alliance was created.
References:
1. “Resid to propylene,” ERTC Annual Meeting, 2008, Vienna.
Licensor: Axens and Shaw.
Website: www.axens.net/product/technology-licensing/20043/r2p-resid-topropylene.html
Contact: www.axens.net/contact.html
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Coking—Delayed coking
Fuel gas
Application: Conversion of atmospheric and vacuum residues, hydrotreated and
hydrocracked resids, asphalt, pyrolysis tar, decant oil, visbroken preheating pitch,
or coal tar pitch, solvent-refined and Athabasca bitumen.
Description: Feedstock is introduced (after heat exchange) to the bottom of the
coker fractionator (1), where it mixes with condensed recycle. The mixture is pumped
to one of two coke drums (3) through the coker heater (2), where the desired coking
temperature is achieved. Steam or boiler feedwater is injected into the heater tubes
to prevent coking in the furnace tubes. Coke drum overhead vapors flow to the
fractionator (1), where they are separated into an overhead stream containing the
wet gas, liquefied petroleum gas (LPG) and naphtha and two gasoil sidestreams.
The overhead stream is sent to a vapor recovery unit (4), where the individual
light product streams are separated. The coke that forms in the drums is then removed
using high-pressure water. The plant also includes a blow-down system for (recovery
of all vent gas and slop streams), coke handling system and a water recovery system.
Operating conditions:
Heater outlet temperature, 900°F–950°F
Coke drum pressure, 15–90 psig
Recycle ratio, vol/vol feed, 0%–100%
Yields:
Middle East
Feedstock
vacuum residue
Gravity, °API
7.4
Sulfur, wt%
4.2
Conradson carbon wt%
20
Products, wt%
Gas + LPG
7.9
Naphtha
12.6
Gasoils
50.8
Coke
28.7
4
3
Coker naphtha
3
Stm.
Stm.
2
BFW
1
Light gasoil
BFW
Heavy gasoil
Fresh feed
Vacuum residue of
hydrotreated bottoms
1.3
2.3
27.6
Athabasca
bitumen
2.5
5.7
23
9
11.1
44
35.9
9.2
12.5
46
32.5
Economics:
Investment (basis: 20,000 bpsd straight-run vacuum residue feed, US Gulf Coast
2008, fuel-grade coke, includes vapor recovery), $8,000/bpsd (typical)
C3/C4 LPG
Stm.
Economics (continued):
Utilities, typical/bbl of feed:
Fuel, 103 Btu
Electricity, kWh
Steam (exported), lb
Water, cooling, gal
Boiler feedwater, lb
Condensate (exported), lb
123
3.6
1
250
38
24
Installation: More than 60 units.
Reference: Sieli, G. M., A. Faegh and S. Shimoda, “The impact of delayed coker
operating conditions on refinery operations,” ERTC Coking & Gasification Conference,
April 16–18, 2007.
Licensor: Chevron Lummus Global (CLG), a 50/50 JV between Chevron USA Inc and
CB&I company
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Coking—Delayed coking
Application: SINOPEC’s delayed coking technology is a thermal-cracking process
to upgrade and convert petroleum residue, asphalt or slop oil, etc,. into gas, naphtha,
gasoil, petroleum coke, etc.
Description: Key points of SINOPEC’s delayed coking technology include:
• Premium petroleum coke (needle coke) can be produced. Operations can
be flexibly adjusted in line with market demands.
• Double-fired, multi-point steam (or H2O) injection, online spalling, bidirectional
steam/air decoking and other techniques enable a 3-yr run length for the heater.
• The automation and safety interlock design techniques for steam stripping, water
quench, coke cooling, hydraulic decoking and oil/gas preheating operations of
the coke drums not only reduce work intensity and ensure safe operation, but
also create conditions to reduce the drum-cycle time to between 16 hr–18 hr.
• The quench oil and anti-foaming agent injection and volume control prevent
foaming of the coke drum and fines carry-over into the fractionator.
• During the process from steam stripping to water quench, the oil vapor and
steam enter a blowdown system, which treats the vapor and steam in a closed
mode by stages. The blowdown system can not only recover oil and H2O
and reduce environmental pollution, but it also can process the similar oil
and wastewater of the whole refinery.
• The high-efficiency internals improve separation accuracy and enable operation
flexibility; coke fine carry-over is reduced.
• The coke cooling H2O and coke cutting H2O are treated separately in closed
systems and then recycled for reuse to protect the environment.
Installations: More than 70 units have been licensed, with a total capacity of more than
70 MMtpy. The maximum design capacity of a single delayed coking unit is 5.2 MMtpy.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-69166661
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Coking—Delayed coking
Application: The coking process involves the cracking of heavy residual oils into
more valuable gasoil, distillate, naphtha and LPG products. Coke is also produced.
Normal feeds include vacuum bottoms, atmospheric bottoms, asphaltenes from
ROSE and other types of solvent deasphalting units, bitumen and other heavy oils,
thermal and pyrolysis tars and decant oils.
Description: Delayed coking is a semi-batch thermal cracking process. The process is
comprised of coker heaters, coke drums, fractionation, a vapor recovery unit, hydraulic
decoking, coke handling and blowdown systems. Feed is normally routed via coker
fractionator to remove light fractions. Feed plus the recycle from the fractionator are
brought to coking temperature in a specially designed heater, and then sent to the
coke drum. The feed cracks into lighter fractions and coke in the coke drum. Cracked
material exiting from the overhead is quenched and sent to the fractionator.
After the coke level in the drum has reached the maximum accepted level, the
feed is directed to the second drum. The drum with coke is cooled, then cut with highpressure water jets and removed to the coke handling area. The drum is then heated
and put back into service.
Advantages: Among the key process application advantages are a solution to
obtaining anode-grade coke from traditional crudes, which lies in alternative lowsulfur, low-metals content feed options to the coker unit. The resin product from the
three-product ROSE® process is a relatively low-metal, low-sulfur residuum that is high
in asphaltene-free Conradson carbon residue (CCR). Due to these characteristics, the
resin is very good for producing higher-quality coke and an excellent feedstock for the
production of anode-grade coke.
Clarified slurry oil (CSO) from the fluid catalytic cracking unit (FCCU) may not
have the superior quality required for producing high-value distillate products; however,
it can still be blended with the ROSE resin to be used as feedstock for anode-grade
coke production. An optimum feed to the delayed coker to produce anode-grade coke
would be a blend of the resin from the ROSE process, the CSO from the FCCU and
the required amount of vacuum residue to compensate for any quality giveaway. This
provides the refiner with the ability to minimize the impact on the anode coke quality
from fluctuations in the feed, irrespective of the crude quality.
KBR has designed and licensed many delayed coking units based on significant
pilot plant work on coking of asphaltenes derived from bitumen and other heavy oils of
heavy crudes around the globe.
Vapors to recovery
Fuel gas
VRU
Blowdown
Slop oil to
coker feed
LPG
Naphtha
Water
Water
Makeup
water
Hydraulic
decoking
Light GO
HGO
Steam
Coke
handling
Steam
BFW
BFW
Crushed coke
Resid feed
Comparison of coke produced from Vacuum Resid and Asphaltenes:
Arab Heavy
Mayan
VR
Asphaltenes
VR
Asphaltenes
Feed(Mbpd)
49.7
26.5
63.7
49.1
Wt% CCR
23.8
38.0
31.2
38.0
Coke Make, MTD
2.7
2.1
4.4
4.0
Installations: KBR has provided this process technology for more than 50 cokers.
The most recent design is for a bitumen vacuum residue coker.
Licensor: KBR Inc.
Contact: technologyconsulting@kbr.com
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Coking—Delayed coking technology
To VRN
Application: The delayed coking process is essentially a thermal cracking process
that is predominantly intended to upgrade bottom-of-the-barrel or residual oil into
salable liquid products, such as mixed LPG, coker naphtha, light coker gasoil and
heavy coker gasoil. The process produces solid byproducts—petroleum coke and fuel
gas—and is also utilized to produce specialty coke for making aluminum and steel.
Flexibility in processing a variety of feedstocks is one of the important features
of delayed coking units, which can process nearly all kinds of difficult-to-process
feedstocks to produce higher-value liquid. Chevron Lummus Global’s (CLG’s) delayed
coking technology has been used to successfully process a wide variety of individual
and blends of feedstocks, including: vacuum resids derived from various crude oil
sources; visbroken resids; solvent deasphalted tar; hydrocracked feedstocks; heavy
Venezuelan resid; and Canadian heavy and extra-heavy bitumen/Athabasca bitumen.
Feedstocks used for producing specialty coke include pyrolysis tar, FCCU
decanted oils, coal tar pitches and solvent-refined coal.
The CLG advanced delayed coking technology offers low pressure and ultra-low
recycle operation, providing maximum liquid yield while minimizing production of
coke for units that operate in fuel mode. CLG two-step coking technology enables
production of high-quality needle coke, which is used in manufacturing electrodes
of high quality.
Process Description: Feed is charged to the unit and preheated in a number of
exchangers for optimum heat recovery and minimization of coker heater duty before
entering the bottom of the main fractionating column. The preheated feed mixes
with the recycle stream, which is generated as a result of contact between coke drum
vapors and wash oil. The combined stream (the heater charge) is then sent to the
fired heater. Steam is used as a velocity medium to increase turbulence and reduce
residence time inside the heater coils. The specially designed heater allows long heater
run-length for increased onstream unit operating time.
The two-phase liquid/vapor mixture leaves the heater via a heater transfer line
and is accepted into one of two coke drums in the coking (filling) mode. Vapors
generated as a result of cracking/coking reactions leave the coke drums via an
overhead line into the main fractionator, where separation into different liquid product
streams and wet gas occurs. The formed coke inside the drum is cooled and removed
with the aid of hydraulic coke cutting equipment once the fill cycle is completed.
Different grades of coke are produced using the delayed coking technology.
Fuel-grade coke is used as feed to gasification units or in the cement manufacturing
industry. Anode-grade coke is used to make carbon blocks that serve as positive
To SWS
Wild naphtha
Light gasoil
Rich sponge oil
Residual oil
Heavy gasoil
electrodes inside the electrolytic cells (or “pots”) in aluminum smelters. Needle coke,
which is highly structured, is used to manufacture graphitized electrodes for the
production of steel through electric arc furnaces.
Operating conditions: The effects of major operating conditions on product yield are
shown here.
Increasing
Coke drum operating pressure
Unit recycle rate
Coil outlet temperature
Gas yield



C5+ liquid yield



Coke yield



Yields: Product yield is dependent on feedstock quality and operating/design
conditions of the unit.
Continued 
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Coking—Delayed coking technology (cont.)
Advantages: CLG licensed delayed coking technology offers mechanical and
operational reliability through the application of state-of-the-art coker fired heater
technology, vertical plate coke drum designs and Helixchangers®.
Development/Delivery: CLG owns a coker pilot plant facility in Pasadena, Texas
that is supporting developmental work for feed pretreatment and coking,
as well as client needs.
Installations: CLG has licensed and designed more than 60 delayed coking units
for all modes of coker operation. The first licensed unit was designed and constructed
in 1938 for Gulf Oil Co. CLG was the first licensor to successfully commercialize delayed
coking of coal tar pitch for the production of anode/needle coke. CLG’s two-step
coking technology has been used for the design and construction of the AIRCO
Seadrift facility for the production of high-quality needle coke.
References:
1. Meyers, R. A., Handbook of Petroleum Refining Processes, 4th Ed., Chapter:
“Chevron Lummus Global’s advanced coking technology for modern refineries,”
McGraw-Hill, 2016.
Licensor: Chevron Lummus Global
Website: www.chevronlummus.com
Contact: Al.Faegh@cbi.com
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Coking—SYDEC℠
Dry gas
Application: Upgrade residues and other heavy streams to lighter hydrocarbon
fractions using the Selective Yield Delayed Coking (SYDEC) process.
Description: A charge is fed directly to the fractionator (1), where it combines
with recycle and is pumped to the coker heater. The mixture is heated to coking
temperature, causing partial vaporization and mild cracking. The vapor-liquid mixture
enters the coke drum (2 or 3), where further cracking converts the trapped liquid
to light hydrocarbon vapors and residual coke. Drum overhead vapors enter the
fractionator (1) to be separated into gas, naphtha, and light and heavy gasoils. Gas and
naphtha from the fractionator enter the vapor recovery unit (VRU) (4).
A minimum of two drums are required for operation due to the semi-batch
nature of the process. One drum receives the furnace effluent, which is converted to
coke and gas while the other drum is being decoked. The coking unit also includes
coke handling, coke cutting, water recovery and blowdown systems. Vent gas from the
blowdown system is recovered in the VRU.
Operating conditions: Typical ranges are:
Heater outlet temperature, °F
Coke drum pressure, psig
Recycle ratio, volume recycle/volume fresh feed
900–950
15–100
0%–100%
A higher coking temperature decreases coke production, while increasing liquid
yield and gasoil endpoint. Increasing pressure and/or recycle ratio increases gas and
coke make, resulting in decreased liquid yield and gasoil endpoint.
Example Yields: Maximum distillate mode
Feed: E.g., Heavy VR
Products, wt% of fresh feed
C4–
8.6
Naphtha
6.9
Gasoil
56.4
Coke
28.1
Advantages: The Amec Foster Wheeler SYDEC process achieves maximum clean
liquid yields, high onstream factors and 5 yr or more run length between turnarounds.
The design is optimized for safe and reliable operation.
4
2
VRU
3
C3/C4
Naphtha
1
Steam
Light gasoil
Heavy gasoil
Feed
Economics:
Investment: For a delayed coking unit, a cost in the $50,000–$115,000 range per
short-ton-per-day of coke produced may be used for preliminary evaluations, with the
lower cost applicable to larger units enjoying economies of scale, and the higher cost
applicable to very small units, such as needle cokers.
Utilities: Utility consumption can vary widely, depending on processing objectives
and selected configuration. Typical values per 1,000 bbl of feedstock processed are
provided here.
Fuel produced, MMBtu
132*
Electricity consumed, kWh
3,375
Steam produced, lb (net)
12,000
* Fuel indicated is net export after consumption in the fired heater.
The delayed coking process is a net exporter of fuel gas.
Continued 
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Coking—SYDEC℠ (cont.)
Development: Amec Foster Wheeler offers advanced flow schemes that combine
proven technologies of solvent deasphalting (SDA) and delayed coking. The SDAcoking combination offers a unique opportunity to further increase liquid yields and
maximize revenue. This flow scheme improves overall refinery margins and can be
used to debottleneck existing delayed coking units in a revamp scenario.
Amec Foster Wheeler endorses and recommends the use of the center feed
device (CFD) in all delayed coking units, and has entered into an alliance agreement
with DeltaValve, manufacturer of the CFD.
Installations: Presently, more than 70 SYDEC delayed coking units are installed
worldwide, with a total installed capacity of more than 2.7 MMbpsd.
References:
1. Handbook of Petroleum Refining Processes, 4th Ed., pp. 583–623, McGraw-Hill,
2016.
2. Beeston, S., “Latest developments in delayed coking,” ME Tech, Dubai, UAE,
February 2017.
3. Srivatsan, S., “Optimizing distillate yields and product qualities,” RefComm,
Bahrain, November 2015.
4. Gillis, D., “Opportunities to maximize high value products and profitability
through zero residue refining,” ARTC, Kuala Lumpur, Malaysia, March 2013.
Licensors: Amec Foster Wheeler
Website: www.amecfw.com
Contact: Coking@amecfw.com
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Coking—ThruPlus® Delayed Coking
Gas
Application: The Bechtel ThruPlus® delayed coking process is a thermal cracking
process used to upgrade petroleum residuum to liquid and gas streams yielding solid
petroleum coke. The unit can handle a wide variety of feedstocks, including vacuum
tower bottoms, bitumen, solvent deasphalter pitch, slurry oil, thermal and pyrolysis
tar, and hydrocracker bottoms. The process can also process waste streams from the
refinery, such as tank bottoms or API separator sludge.
Description: Fresh feed to the unit is sent to the fractionator (1) bottom, where it
is combined with natural recycle to comprise the feed to the coker furnace (2). The
coker furnace heats the combined stream to cracking temperatures (900°F–950°F).
Residence time in the furnace tubes is limited, so coking of the feed is “delayed”
until it reaches the online coke drum (3), where the reactions are completed. Coke
accumulates in the coke drum, and hot gases exit the top of the drum and flow to
the fractionator, where they are separated into heavy and light coker gasoils, while
lighter gases leave the top of the fractionator. These gases are partially condensed
in the fractionator overhead system (4) before being sent to the gas plant (5), which
separates the overhead into naphtha, LPG and off-gas.
Delayed coking is a batch-continuous process, with continuous flow through
the furnace. When the online coke drum is filled with coke to a predetermined level,
it is switched into an empty, pre-warmed coke drum. The full coke drum is cooled
and decoked using high-pressure water, and then pre-warmed again. A closed
blowdown system is available to recover all water, hydrocarbon liquid and vapor
from the offline drum during these operating steps.
Advantages:
• Distillate technology to maximize naphtha, light coker gasoil or heavy coker
gasoil production
• Demonstrated best coke drum life in the industry
• Demonstrated best furnace design with maximum furnace run lengths
• Demonstrated 7-yr unit run between turnarounds.
Utilities: typical per bbl feed
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
5
4
3
LPG
Naphtha
Steam
LCGO
1
Coke
Steam
Steam
2
HCGO
Feed
Steam
Installations: Since 1981, 66 grassroots and revamp unit licenses have been sold.
References:
1. Meyers, R. A., Handbook of Petroleum Refining Processes, 3rd Ed.,
pp. 12.3–12.31, McGraw-Hill, 2004.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
3.4
5.0
50.0
120,000
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Deasphalting—ROSE®
Products: Lube blendstocks, synthetic crude, FCCU feed, hydrocracker feed,
resins and asphaltenes outlets can be fuel oil, road asphalt, cement, for coker feed,
power generation feed (i.e., gasifier, pitch boiler, CF boiler), as well as pelletization
for easier transport and usage.
Description: Resid is charged through a mixer (M-1), where it is mixed with solvent
before entering the asphaltene separator (V-1), which uses special internals to achieve
maximum benefit of counter-current solvent flow. The solvent extracts primarily
non-asphaltenic, paraffinic DAO. The asphaltene-rich stream leaves from the bottom
of the separator. The extracted oils and solvent flow overhead (V-1) through heat
exchangers (E-1, E-4, E-6) so that the solvent reaches conditions where it exists
as a supercritical fluid in which the oil is virtually insoluble. Recovered solvent leaves
the separator top (V-3) to be cooled by heat exchange (E-4, E-1) and a cooler
(E-2). The only solvent vaporized is a small amount dissolved in fractions withdrawn
in the separators. This solvent is recovered in the product strippers. Alternately,
an intermediate resin-rich product can be produced in V-2 and T-2.
Advantages: V-1, V-2 and V-3 are equipped with high-performance ROSEMAX
internals. These high-efficiency, high-capacity internals offer superior product yield and
quality, while minimizing vessel size and capital investment. These internals can also be
used to debottleneck and improve operations of existing solvent deasphalting units.
Yields: The solvent composition and operating conditions are adjusted to provide the
highest product quality and yields required for downstream processing, or to meet
finished product specifications. Solvents range from propane to hexane, and almost
always are streams produced in refineries.
E-2
P-1
E-1
E-4
E-3
T-3
T-2
T-1
V-3
E-6
Residuum
V-1
Application: KBR’s Residuum Oil Supercritical Extraction (ROSE) is the market-leading
solvent deasphalting technology that is used to extract maximum volumes of lubes,
fluid catalytic cracking unit (FCCU), or hydrocracker/hydrotreater feedstocks from
atmospheric and vacuum resids and, in some special cases, from whole crude oils.
The extracted deasphalted oil (DAO) yields can be adjusted to optimize integration
with downstream units. The ROSE DAO has “order of magnitude” lower heptane (C7 )
insolubles content, as well as lower metals and conradson carbon (CCR) than other
solvent deasphalting processes. This lower C7 insolubles content allows refiners to
achieve longer run lengths in hydrotreating and hydrocracking units and reduced
catalyst usage in conversion units. Moderate operating temperatures almost alleviate
the need for 317SS metallurgy when processing high-acid crude oils. ROSE is also
useful in the production and upgrading of heavy oils. The process is also used
for debottlenecking of existing vacuum distillation units (VDUs) and cokers.
V-2
PROCESS CATEGORIES
S-1
M-1
Hot
oil
Hot
oil
Asphaltenes
P-2
Oils
Resins
Economics: Investment, ISBL: (Basis: 30,000 bpd, US Gulf Coast), $1,900/bpd
Utilities
Fuel absorbed, 103 Btu
Electricity, kWh
Steam, 150-psig, lb
80–110
1.5–2
12
Development/Delivery: KBR continues to develop delayed coking technology
based on feedback from licensees and other sources.
Installations: KBR has licensed nearly 60 units, with a combined capacity of almost
1.4 MMbpd. More than 30 units are in operation, with six more expected to startup
within the next couple of years.
References:
• Rahman, M. J. and S. Cackett, “Innovative and Cost-effective Bottoms Upgrading,”
METech, February 2017.
Licensor: KBR Inc.
Contact: technologyconsulting@kbr.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Deasphalting—Solvent Deasphalting
Application: Solvent deasphalting (SDA) is used as part of a bottom-of-the-barrel
upgrading solution that separates higher quality components from heavy residues and
other heavy petroleum feedstocks using solvent extraction and supercritical solvent
recovery technology.
Description: Heavy feedstock is diluted with a light paraffinic solvent, and then
charged to a vertical extractor tower. Within the tower, a deasphalted oil (DAO) fraction
dissolves in the solvent and the remaining heavy components are precipitated. The DAO
and solvent mixture exits the top of the extractor and is heated to create a supercritical
solvent phase that is then separated from the liquid DAO phase. Any remaining solvent
is removed in a stripper column, and the DAO product is then typically sent as a quality
feedstock to fuels cracking processes or used in the production of lubricating oils. Pitch
with some entrained solvent is withdrawn from the bottom of the extractor and sent to
a pitch stripping section. The pitch can be used in specification asphalts as fuel, or as
feedstock to conversion units such as a delayed coker or gasifier. If desired, a second
extraction stage is utilized to produce an intermediate resin product.
Operating conditions: Typical extraction conditions are:
Solvent
Typically pure or blended C3–C7 paraffins,
including light naphthas
Extraction pressure, psig
500–700
Extraction temperature, °F
120–400
Solvent-to-oil ratio
4:1 to 10:1
Yields: The depth of extraction can be tailored to each specific application, and may
vary widely since yield/quality is dependent on the molecular species present in the
feedstock. Two examples with widely varying quality targets are listed here.
Lubes application
(C3 solvent)
High-lift fuels
application (C5 solvent)
0.995
1.48
16.0
98
1.047
1.88
27.2
239
31
0.932
0.89
81
0.997
1.5
Feed
Specific gravity
Sulfur, wt%
Conradson carbon residue (CCR), wt%
Metals (Ni + V), wt ppm
DAO
Yield, vol% of feed
Specific gravity
Sulfur, wt%
DAO
separator
Extractor
Feed
Hot oil
Pitch
stripper
Hot oil
Pitch
CCR, wt%
Metals (Ni + V), wt ppm
Pitch
Ring and ball softening point, °F
Specific gravity
DAO
stripper
DAO
2.5
<2
14.0
32
130
1.02
425
1.26
Advantages: The UOP/Amec Foster Wheeler SDA process is a state-of-the-art solvent
extraction process incorporating supercritical solvent recovery, and is capable of
achieving the highest product quality with the lowest operating costs. The technology
incorporates a long history of proven deasphalting and heavy oils experience and
is designed to ensure reliable operations.
Economics:
Investment: Deasphalting should be considered when selecting any modern
bottom-of-the-barrel upgrading scheme. Stand-alone units or residue blocks
incorporating deasphalting are often attractive due to a much lower investment
cost, typically leading to higher overall project internal rates of return (IRRs).
Continued 
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Deasphalting—Solvent Deasphalting (cont.)
Utilities: Utility consumption can vary greatly depending upon processing
objectives. Typical values are listed here. Heat input is typically provided by steam
or hot oil.
Electricity, kWh
1.6
per bbl of feed
Stripping steam (150 psig), lb
11
per bbl of feed
Heat absorbed, MMBtu
0.080
per bbl of feed
Development/Delivery: Joint licensors UOP and Amec Foster Wheeler have
well-established experience in licensor technology packages; front-end engineering;
engineering, procurement and construction (EPC); operating unit support;
and pilot plant testing.
Installations: More than 60 units licensed or designed, with single trains
up to 50 Mbpsd.
References:
1. Handbook of Petroleum Refining Processes, 4th Ed., pp. 475–495,
McGraw Hill, 2016.
2. “Solvent deasphalting options: How SDA can increase residue upgrading
margins,” Middle East Technology Forum, Dubai, UAE, February 2014.
Licensor: Amec Foster Wheeler/UOP, A Honeywell Company
Websites: www.amecfw.com
www.uop.com/processing-solutions/refining/
Contact: Deasphalting@amecfw.com
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Deasphalting—Solvent Deasphalting
Deasphalted oil
Application: A process to produce deasphalted oil (bright stock) from vacuum
residues for further processing in downstream units to produce lubricating base oils
or feedstock for catalytic cracking and hydrocracking.
Description: Feedstock is cooled to extraction temperature and counter-currently
treated with solvent in an extraction tower. Steam coils near the top of the extractor
control the temperature gradient, providing reflux and maximum selectivity of
separation. Deasphalted oil containing most of the solvent is withdrawn from the
top. The major portion of the solvent is evaporated from the oil under pressure, and
the remaining solvent is steam-stripped off the oil under vacuum. The asphalt from
the bottom of the extraction tower is heated under pressure to recover the solvent,
followed by steam-stripping for removal of solvent traces.
Deasphalted
oil recovery
Extraction
tower
STM
Feed
Asphalt
recovery
Feeds: Vacuum residues from crude oils.
Products: Deasphalted oils with bright color, low Conradson carbon residue and
negligible resins, asphalt and metals content for use as lubricating base oils or
feedstock for catalytic cracking and hydrocracking. A byproduct is asphalt with
a high softening point.
Utilities: (per m3 of feed)
Electricity
15
LP steam
380
Cooling water
7
Fuel energy
400
15 kWh
340 kg
6 m³
11 kWh
STM
Solvent
makeup
Solvent
accumulator
Sewer
Asphalt
Solvent
Installations: Numerous installations under thyssenkrupp license are in operation
around the world.
Licensor: The former proprietor of this technology was ThyssenKrupp Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Desulfurization—
Advanced Ammonia Claus
Air
Application: Recovery of sulfur from sour water stripper (SWS) gas, regardless of the
ammonia (NH3 )/hydrogen sulfide (H2S) ratio in the combined stream from the burner.
Description: This technology represents a further enhancement to the traditional
ammonia Claus technology. The thermal reactor of the Claus process is modified to
accommodate two subsequent partial oxidation stages. The first oxidation stage is
carried out on the gaseous ammoniacal stream, optionally containing H2S. The second
oxidation stage takes place on the gaseous stream with the higher concentration of H2S.
Both partial oxidations are carried out with air or with a stream formed by
air and pure O2 (enriched air). The ammoniacal stream is partially oxidized, in slight
deficiencies of oxygen, at a high temperature to ensure the substantial destruction
of NH3. The oxidizing element, necessary for NH3 decomposition and H2S conversion,
is divided into two distinct streams, proportional to the NH3 and H2S flowrates,
respectively contained in the ammoniacal gas and in the acid gas. Each stream is
introduced in the thermal reactor in correspondence with the feedings of the two
process streams. In particular, the oxidizing element in the second oxidizing stage
is fed by means of a special internal distributor. The gaseous stream that results
from the partial oxidation stages feeds the Claus process catalytic section for the
recovery of sulfur.
Operating conditions: For feedstock with a high NH3 /H2S ratio.
Yields: Up to 95% sulfur recovery as standard Claus with two catalytic converters.
Advanced ammonia burner
SWSG
Themal reactor
AAG
Installations: Italian refinery
Licensor: Siirtec Nigi S.p.A.—Process Department
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Contact: marketing@siirtecnigi.com
Advantages: Debottlenecking of the traditional ammonia Claus.
Investment: Similar to a standard Claus unit, with a slight increase in thermal
reactor dimensions.
Utilities: Power and water as standard Claus. Enriched air technology may be applied.
Development/Delivery: Siirtec Nigi’s R&D development; patented technology;
first commercial tryout
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Desulfurization—Amine Treating
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers a
complete suite of sulfur block technologies, including amine treating. Amine treating
removes acid gases [hydrogen sulfide (H2S) carbon dioxide (CO2 ) and carbonyl sulfide
(COS)] from fuel gas headers, hydrotreaters (DHT, NHT, etc.), coker off-gases and LPG.
Depending on the service, the amine used includes MEA, DEA, DGA, DIPA, MDEA and
proprietary activated amine, any of which BHTS will evaluate.
Description: The typical sour gas stream is saturated with hydrocarbons, so a sour
KO drum (1) removes entrained liquid before entering the amine absorber (2), where
the amine flows counter-currently. The amine absorbs acid gas, and the sweet gas is
returned to the refinery through a KO drum (3), which recovers entrained amine to
reduce carry-over losses and OPEX.
The amine rich in acid gases is flashed to about 5 psig (or flare header pressure)
(4) to remove entrained hydrocarbons and allow phase separation from light
hydrocarbons. Flashed vapors are flared or recovered by a wet gas compressor.
Recovered hydrocarbon liquids are typically sent to the refinery slop-oil system.
The rich amine is then pumped (5) through a filtration system (not shown) to
remove particulates and entrained hydrocarbons to minimize downstream erosion,
fouling and loss of performance, before being pre-heated (6). It then enters the
regenerator (also called a stripper, 7), in which vapor, generated in the reboiler (11),
strips the acid gases from the amine. From the regenerator bottoms, the lean amine is
pre-cooled (6) and pumped (12) through the lean-amine coolers (13), which can be a
combination of air- and water-cooled exchangers, back to the absorber.
The regenerator overhead gas is cooled (8), and reflux (sour water) is recovered
(9) and pumped (10) back to the regenerator. The amine acid gas is typically then sent
to a sulfur recovery unit (SRU). Water balance is critical to meeting specifications, and
is maintained by either purging sour water reflux or adding water to the regenerator
overhead (acting as an ammonia wash), which benefits the SRU.
Sweet gas
Amine acid gas
Fresh water makeup
(8)
(3)
(9)
(13)
(12)
(10)
(2)
Flash gas
(6)
(7)
Sour water purge
LP steam
Sour gas
(4)
(1)
(11)
(5)
Installations: This process has been used in thousands of units worldwide
to produce low-sulfur and low-CO2 process streams.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
Advantages: Bechtel’s amine treating units can reduce contaminant acid gases
to the standard US fuel gas specification of 160 ppmv H2S or lower. With specialty
amines, concentrations as low as 10 ppmv can be reached.
Utilities: typical per gal of feed
Electricity, kWh
Steam (LP), lb/gal of amine circulation
Water, cooling (25°F), gal
Fuel (absorbed), Btu
0.01
1.0
3.8
0
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COMPANY INDEX
Desulfurization—Ammonia Claus
Application: Sulfur recovery from sour water stripper (SWS) gas and amine acid gas.
Description: In case of high ammonia (NH3 ) concentrations, especially from
an SWS gas stream, NH3 must be destroyed to avoid severe operational problems
in the sulfur recovery units (SRUs). To fully destroy NH3 , a “two-zone furnace” is
typically used. The NH3 -bearing stream is burned with part of the amine acid gas in
Zone 1 at high temperature, followed by the injection of the remaining amine acid gas
into Zone 2 of the reaction furnace. A properly designed burner that has excellent
mixing characteristics is used to easily reach the required high-temperature levels.
By adopting the Ammonia Claus technology, the NH3 concentration in the
furnace’s effluent gas does not adversely affect the SRU operation.
Amine acid gas
Steam
SWS (NH3) off-gas
Air
Zone 1
NH3
burner
Zone 2
Reaction furnace
(two zones)
To condensers/converters
Waste
heat boiler
BFW
Operating conditions: Up to a ratio of NH3 /hydrogen sulfide (H2S) < 0.3
in the overall feedstock.
Liquid
sulfur
Yields: Up to 95% sulfur recovery as a standard Claus with two converters.
Advantages: Disposal of NH3 , making use of a Claus unit
Investment: As per standard Claus
Utilities: Power and water as standard Claus
Development/Delivery: Same as standard Claus
Licensor: Siirtec Nigi S.p.A.—Process Department
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Contact: marketing@siirtecnigi.com
Installations: More than 60 Ammonia Claus plants have been built worldwide, with an
NH3 concentration in the feed stream ranging from 0.5%–30%.
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—CANSOLV® TGT+
Application: Shell sulfur recovery processes are applicable for the conversion of
hydrogen sulfide (H2S) in acid gas streams to elemental sulfur through the modified
Claus process. The Claus unit converts H2S to sulfur and can be targeted to combust
hydrocarbons and other contaminants effectively. Shell sulfer recovery processes can
be applied in combination with other processes at refineries and gas plants aiming for
ultra-high sulfur recoveries. Shell CANSOLV TGT+ is intended for sulfur loads > 5 t/d,
and achieves < 150 ppm of sulfur dioxide (SO2 ).
Description: In the Shell CANSOLV TGT+ process, the Claus sulfur recovery unit (SRU)
tail gas is routed directly to an incinerator, which oxidizes all the sulfur species to SO2 .
This flue gas stream is then routed to a Shell CANSOLV SO2 Scrubbing System that
ensures low SO2 emissions (as low as 10 ppmv). The SO2 -rich stream is routed back to
the Claus unit or to produce H2S. As well as having the potential to address other
SO2 emissions sources such as fluidized catalytic cracker (FCC) regenerator off-gas,
coker off-gas and utility boiler flue gas, it has great benefits in debottlenecking
a Claus SRU when in a lineup with oxygen enrichment.
Advantages:
• The destination for all sour gas contaminants streams in a plant
• Simplified process lineup, fewer process units
• Ultra-high sulfur recovery efficiency of up to 99.99+%
• Centralized treating of all sulfur-containing process off-gases
• Access to World Bank standards associated capital
• Reduced or eliminated transportation (reagent and waste)
and landfill obligations
• Manages multiple sour streams in one system.
SO2
Acid gas
SWS
Claus
SRU
H2S, COS, S, SO2
Incinerator
Degasser
SO2
Cansolv
Sulfur
References:
1. Lebel, M., “Alternative solution to handling sulphur processing capacity increase,”
GPA GCC, May 2017.
2. Demmer, A. and P. Chilukuri, P., “Cost-effective and innovative emissions
reduction configurations in sulphur recovery and tail gas treating units,”
SOGAT conference, March 2017.
3. Bowerbank, G. and P. Chilukuri, “Why choose a one-size-fits-all tail gas treating
unit?” Middle East Sulphur, February 2017.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
Development/Delivery: Shell is both an operator and licensor, which leads to
optimized design margins and applied lessons. Shell has more than 60 years of
licensing experience, more than 100 years of operational experience and in-housedeveloped processes.
Installations: Shell CANSOLV was developed in the mid-1990s, primarily for treating
SO2 from coal-fired power plants and other SO2 -containing flue gas. The first
applications linked to the Claus process and acid plant tail gas units were in 2002.
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2017 REFINING PROCESSES HANDBOOK
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Desulfurization—Claus Sulfur
Recovery Units
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers a complete
suite of sulfur block technologies, including Claus sulfur recovery units (SRUs).
Environmental regulations limit sulfur compounds in refining products, natural
gas and discharge streams. The Claus SRU takes acid gas that has been removed
from various refinery products or natural gas and converts hydrogen sulfide (H2S)
to liquid sulfur, and ammonia (NH3 ) and hydrocarbons to nitrogen, water vapor,
carbon monoxide (CO) and carbon dioxide (CO2 ).
Permutations include the handling of NH3 with H2S from a sour water stripper
(SWS), indirect reheat with HP steam generated within the SRU, low-level oxygen
(O2 ) enrichment (up to 28% O2 equivalent), high-level O2 enrichment (up to 50%
O2 equivalent), sub-dew-point operation, processing of very lean acid gas (< 15% H2S),
and more.
Description: First, the feed gases are partially combusted in the thermal reactor (1) to
produce sulfur. The process gas is then cooled in the high-pressure, waste heat boiler
(2) and the LP steam generating sulfur condenser (3) until sulfur condenses as a liquid
and is removed.
The remaining process gas is then sent through three catalytic reactor stages,
where additional sulfur is produced. Each stage consists of a reheat exchanger (4), a
catalytic reactor (5) and a sulfur condenser (6). The sulfur produced in the catalytic
reactors condenses and is removed. The liquid sulfur product flows into a sulfur
storage pit (7) or tank, and is pumped to truck or rail car loading for transport.
Depending on local environmental regulations, the effluent (SRU tail gas)
from the SRU is sent either to the Claus tail gas treating unit (TGU) for additional
processing, or to a thermal oxidizer for combustion and discharge.
Advantages: Bechtel’s Claus SRU produces liquid sulfur that meets all industrial
standards for color, ash and contaminants. The company also offers degassing—
that is, the removal of H2S and other dissolved gases to meet most sulfur solidification
units’ specifications. The resulting degassing carrier stream can be incinerated
or returned to the Claus SRU feed.
Amine acid gas
(4)
SWS acid gas
(2)
(5)
(3)
(6)
SRU tail gas
Air
(1)
Liquid sulfur
(7)
Utilities: Typical per long ton feed
Electricity, kWh
Boiler feed water (HP), lb
Steam export (HP), lb
Boiler feed water (LP), lb
Steam export (LP), lb
Fuel (absorbed), Btu
79
4,200
4,000
1,800
1,700
0
Installations: The Claus process has been used in thousands of units to produce
millions of tons per year of essentially pure sulfur.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
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Desulfurization—Claus Tail Gas Treating
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers a
complete suite of sulfur block technologies, including Claus tail gas treating units
(TGUs). The hydrogenation-amine TGU is designed to meet environmental regulations
and improves sulfur block efficiency. Depending on service and specifications, BHTS
will select a generic methyl diethanolamine (MDEA) or a proprietary activated amine.
Permutations include the use of special low-temperature catalyst,HP steam from
the sulfur recovery unit (SRU) for the catalytic reactor feed heater rather than a fired
heater-reducing gas generator (if an external source of hydrogen is available), and
specialty amines to improve energy efficiency and reduce sulfur emissions.
Description: The Claus tail gas is combined with hydrogen (H2 ) and heated in the
tail gas feed heater (1) before being sent to the catalytic reactor (2). There, the
non-H2S (non-hydrogen sulfide) sulfur species in the feed gas are converted to H2S.
This reaction generates heat that must be removed before amine treating, so the
heat is used to generate LP steam in the waste heat exchanger (3).
The process gas is further cooled by counter-current water flow in the contact
condenser or quench tower (4) before going to the amine absorber (7), where H2S
and some carbon dioxide (CO2 ) are absorbed. The process gas is then vented to the
incinerator, while the rich amine is sent to the amine stripper-regenerator (8) to remove
the acid gas (see Amine Treating for details), which is recycled back to the SRU.
From quench tower bottoms, the water is pumped (5) to a filtration system
(not shown) before being cooled (6)—which can be accomplished by a combination
of air- and water-cooled exchangers—and returned to the quench tower. Since the
Claus reaction generates one mole of water for every mole of sulfur created, some of
the produced water (containing H2S and CO2 ) must be purged from the quench tower
bottoms and sent to the sour water stripper (SWS) (see Sour Water Treating).
Advantages: Bechtel’s Claus TGU can reduce H2S to as low as 10 ppmv, which can be
vented to atmosphere in the US. This boosts overall sulfur block recovery to 99.9+%
of the incoming sulfur. Custom designs are available to meet World Bank standards of
99.98+% recovery.
Utilities: Typical per long ton SRU feed:
Electricity, kWh
21
Steam (MP), lb
470
Steam (LP), lb
2,300
Water, cooling (25°F), gal
14,000
Hydrogen, SCF
4,200
H2
SRU tail gas
(1)
(2)
(6)
(4)
(3)
Sour water purge
(5)
TGU acid
gas to SRU
Vent gas to Incinerator
(7)
(8)
LP steam
Installations: This process has been used in hundreds of units worldwide
to produce low and ultra-low sulfur discharge streams.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
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Desulfurization—Emission-Free
Sulfur Recovery Unit
Raw gas
Application
Recovery of sulfur from acid gases removal unit and sour water strippers,
producing bright yellow sulfur with up to 99.9% purity and no coproduct.
Description
Raw gas is desulfurized in an acid gas removal unit (AGR) and acid gas is sent to
the emission-free sulfur recovery unit for sulfur recovery. The conventional oxygenbased Claus process is used to recover sulfur from the acid gas in elemental form.
In addition, gases containing hydrogen sulfide (H2S) from sour-water strippers can
be fed to the Claus unit. The recovered sulfur is degassed and is then available as a
sellable product.
Claus tail gas is hydrogenated and cooled before being compressed and routed
back to the upstream AGR. There, it is desulfurized, recycled, together with acid gas,
back to the Claus unit. Other valuable components inside the tail gas,
like H2 and CO, end up in the purified gas. With this recycle, a sulfur recovery rate
of 100% is achieved. The sulfur emissions to atmosphere in the overall complex
are significantly reduced, because no incineration is used.
OxyClausTM is used in this concept because this reduces the process gas volume,
and thereby lowers not only investment plus operating cost but also the amount of
inert gas sent to the AGR unit.
Acid gas
Tail gas recycle
Claus tail gas
Claus/OxyClaus™
Degassing
Purified gas
AGR (Purisol™ or Rectisol™)
Tail gas
Hydrogenation quench
Tail gas compression
Sulfur
Advantages
Up to 1,000 tpd and 100% sulfur recovery.
Economics
CAPEX: 25% less than conventional amine wash tail gas treatment.
Installations
Three emission-free SRUs have been designed; one has been in operation
for 25 years.
Website: https://www.engineering-airliquide.com/sulfur
Contact
sulfur@airliquide.com
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Desulfurization—FCC Gasoline—
Prime-G+™
Application: Deep selective hydrodesulfurization of FCC naphtha to produce ultralow-sulfur gasoline while preserving octane.
Description: Prime-G+technology comprises a selective hydrogenation reactor (SHU)
featuring diolefins saturation to protect the downstream hydrodesulfurization section
(HDS) from pressure drop, thus maximizing the cycle. The SHU also achieves the sulfur
shift by converting light mercaptans and sulfides into heavy mercaptans, which boil
within heavy fraction (HCN)—this is essential to produce a sweet light gasoline (LCN)
at 10 wppm sulfur.
SHU effluent is fractionated in a splitter to recover the LCN at the top, saving
C5 olefins and maximizing octane. The LCN is sent directly to the pool. The HCN at
splitter bottoms is rich in sulfur and has moderate olefins content, which enables
deep hydrodesulfurization in the HDS section while maximizing octane retention
and minimizing hydrogen consumption. Desulfurized effluent is separated. The liquid
gasoline is stabilized and sent to the pool. The hydrogen (H2 )-rich gas is scrubbed for
hydrogen sulfide (H2S) removal and recycled back to the reactor.
Different configurations exist depending on octane, plot plan, budget or existing
equipment limitations: although the splitter is optional depending on the required
octane retention, the association of SHU and splitter for sweet LCN production ideally
complements the selective HDS on the HCN. The HDS section arrangement can vary:
a single-stage HDS, a two-stage HDS or a three-cuts scheme with the generation of
medium naphtha (MCN).
Catalysts feature excellent selectivity, enabling deep hydrodesulfurization while
maximizing octane retention, a low sensitivity to impurities and excellent stability due
to their optimized metal content and neutral carrier, which is essential to match FCC
turnaround. Catalysts can be fully regenerated.
Advantages:
Process features
Very high HDS level (> 99%) with
recombinant mercaptans control
Benefits
Achieves toughest gasoline pool sulfur
specifications: 10 ppm
LCN to MS pool
FRCCN
SHU reactor
Selective HDS
Splitter
Purge
Stabilizer
HCN
H2 makeup
HCN to MS pool
Compressor and
amine scrubber
Simple process scheme
Easy operation
Easy idle units retrofitting
Flexibility
Handle feedstock fluctuations while meeting
performance requirements
Co-processing of opportunity naphthas
(light coker, visbreaker, straight run, pygas)
Installations: More than 285 references worldwide, with a cumulative capacity
exceeding 7 MMbpsd.
References:
1. Sanghavi, K. and J. Schmidt, “Achieve success in gasoline hydrotreating,”
Hydrocarbon Processing, September 2011.
2. Margotin, J.-P., “10-ppm sulfur gasoline opportunity analysis,” Journal of
Petrotech, October 2013.
Low olefins and no aromatics
hydrogenation
Low H2 consumption
High octane retention
No cracking reactions
100% liquid yield with no RVP increase
Website: www.axens.net/product/process-licensing/10084/prime-g+.html
Reliability
Long cycle lengths matching FCC turnaround
Contact: information@axens.net
Licensor: Axens
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—Flue gas
Cleaning—SNOX™
Application: The SNOX process treats boiler flue gases from the combustion of highsulfur fuels, such as heavy residual oil and petroleum coke. The SNOX process is a
combination of the Topsoe Wet Gas Sulfuric Acid (WSA) process and the Topsoe SCR
DeNOx process. The process removes SO2 , SO3 and NOx, as well as dust. The sulfur
is recovered in the form of concentrated commercial-grade sulfuric acid. The SNOX
process is distinctly different from most other flue gas desulfurization processes in
that its economy increases with increasing sulfur content in the flue gas.
Description: Dust is removed from the flue gas by means of an electrostatic
precipitator or a bag filter. The flue gas is preheated in a gas/gas heat exchanger.
Thereafter, it is further heated to approximately 400°C and ammonia is added
before it enters the reactor, where two different catalysts are installed. The first
catalyst makes the NOx react with ammonia to form N2 and water vapor, and the
second catalyst makes the SO2 react with oxygen to form SO3. The second catalyst
also removes any dust traces that remain. During the cooling in the gas/gas heat
exchanger, most of the SO3 reacts with water vapor to form sulfuric acid vapor.
The sulfuric acid vapor is condensed via further cooling in the WSA condenser,
which is a heat exchanger with vertical glass tubes. Concentrated commercial-grade
sulfuric acid is collected in the bottom of the WSA condenser and is cooled and
pumped to storage. Cleaned flue gas leaves the WSA condenser at 100°C and
can be sent to the stack without further treatment. The WSA condenser is cooled
by atmospheric air. The cooling air can be used as preheated combustion air in the
boiler. This process can achieve up to 99% sulfur removal and about 96% NOx removal.
Other features of the SNOX process includes:
• No absorbent is applied.
• No waste products are produced. Besides dust removed from the flue gas,
the only products are cleaned flue gas and concentrated commercial-grade
sulfuric acid.
• Boilers equipped with SNOX have carbon footprints 5%–10% lower than
similar boilers equipped with traditional limestone FGD.
• A high degree of heat efficiency.
• A modest utility consumption.
Cleaned gas
Heavy oil
or Petcoke
Boiler
Blower
Air
SCR DeNOx
and SO2 reactor
WSA
condenser
Flue gas
Filter
Air
preheater
Flue gas
blower
Acid cooler
Heat
exchanger
Support
heat
NH3
Product acid
• An attractive operating economy.
• A simple, reliable and flexible process.
Installations: Six SNOX units have been contracted for cleaning with a total of
more than 5 MMNm3/h of flue gas. Additionally, 150 WSA plants have been
contracted. These WSA plants are similar to SNOX plants, only smaller,
some without NOx removal, for applications other than flue gas cleaning.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: Topsoe.com
Contact: kich@topsoe.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—GT-BTX PluS®
C5-
Application: GT-BTX PluS accomplishes desulfurization of fluid catalytic cracking
(FCC) gasoline, with no octane loss and decreased hydrogen (H2 ) consumption,
by using a proprietary solvent in an extractive-distillation system. This process also
recovers valuable aromatics compounds that can be used as petrochemical feedstock.
Description: The optimum feed is the mid-fraction of FCC gasoline from 70°C–150°C.
This material is fed to the GT-BTX PluS unit, which extracts the sulfur and aromatics
from the hydrocarbon stream. The olefin-rich stream from the GT-BTX PluS, now
without sulfur, can surpass the hydrodesulfurization (HDS) unit to blend directly
with the gasoline pool. The sulfur-containing aromatic components are processed
in a hydrotreater to convert the sulfur into hydrogen sulfide (H2S). Because the
portion of gasoline being hydrotreated is reduced in volume and free of olefins,
H2 consumption and operating costs are greatly reduced. In contrast, conventional
desulfurization schemes must process the majority of the gasoline through
hydrotreating units to remove sulfur, which inevitably results in olefin saturation,
octane downgrade and yield loss.
FCC gasoline is fed to the extractive distillation column (EDC). In a vapor-liquid
operation, the solvent extracts the sulfur compounds into the bottoms of the column
along with the aromatic components, while rejecting the olefins and non-aromatics
into the overhead as raffinate. Nearly all of the non-aromatics, including olefins, are
effectively separated into the raffinate stream. The raffinate stream can be routed to
the gasoline pool, to an aromatization unit to further increase benzene, toluene and
xylene (BTX) production, or recycled to the FCCU to produce additional propylene.
Rich solvent, containing aromatics and sulfur compounds, is routed to the solvent
recovery column (SRC), where the hydrocarbons and sulfur species are separated,
and lean solvent is recovered in columns bottoms. The SRC overhead is hydrotreated
by conventional means and either used as desulfurized gasoline or directed to an
aromatics plant. Lean solvent from the SRC bottoms is recycled back to the EDC.
Operating conditions:
S/F ratio*
EDC bottom temperature*
SRC bottom temperature
*Reformate feed only
2.5 v/v–3.5 v/v
155°C–170°C
< 180°C
GT-BTX PluS
Full-range
FCC naphtha
Aromatics/
sulfur-rich
extract
H2
Feed
fractionation
Gasoline pool
H2S
HDS
Process Advantages: The technology advantages include:
• Eliminates FCC gasoline sulfur species to meet a pool gasoline target
of 10 ppm sulfur
• Rejects olefins from being hydrotreated in the HDS unit to prevent loss of octane
rating and to reduce H2 consumption
• Fewer components (only the heavy-most fraction and the aromatic concentrate
from the ED unit) are sent to HDS, resulting in a smaller HDS unit and less yield loss
• Purified benzene and other aromatics can be produced from the aromatic-rich
extract stream after hydrotreating
• Olefin-rich raffinate stream (from the ED unit) can be directed to
an aromatization unit to produce additional BTX, or recycled to the FCCU
to increase propylene production.
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—HCR™
Application: Remove sulfur compounds present in tail gases from Claus plants,
as well as adhering to air pollution standards.
Description: The HCR process consists of two sections:
• Hydrogenation and hydrolysis of sulfur compounds present in tail gases
[carbonyl sulfide (COS), carbon disulfide (CS2 ), Sx and sulfur dioxide (SO2 )].
Tail gas is heated to approximately 230°C and, without the addition of
hydrogen (H2 ), is treated with cobalt (Co) and molybdenum (Mo) catalyst.
Gas passes through a waste heat boiler and is cooled in a direct contact tower.
• Removed hydrogen sulfide (H2 S) and acid gas are recycled to the Claus
plant. The gas is washed in a methyl diethanolamine (MDEA) absorber, and
the treated gas is thermally oxidized. The semi-rich amine is regenerated
and recycled to the absorber. The process requires adjusting the operating
condition for the Claus unit by increasing the H2S/SO2 tail gas ratio.
The operation is very steady and has high service factors. H2 or a reducing
gas from external sources are not required. Tail gas can be sent to the
sulfur recovery unit’s (SRU’s) thermal oxidizer.
By using a new generation of MDEA, the residual content of H2 S in tail gas
can be reduced below 100 ppmv.
Operating conditions: The pressure drop of the unit is 0.20 bar–0.30 bar,
and the operating pressure is almost atmospheric.
Yields: The most advanced HCR, based on the new generation of reducing catalyst
and MDEA, allows a sulfur recovery efficiency of 99.99%.
Advantages: Very-high sulfur recovery without troublesome operation or operating
costs for reducing gas generation/consumption.
Investment: As per standard Claus and tail gas treatment units.
Utilities: The same is true of the upstream Claus unit, no consumption of fuel gas
and/or H2.
Development/Delivery: Internal development.
Tail gas to incinerator
Pumparound
cooler
Quench
tower
Claus tail gas
Lean amine solution
Reheater
Amine
absorber
Reducing
reactor
Wastewater
filters
Waste heat
boiler
Recycle
pumps
Rich amine to regenerator
Recycle
pumps
Rich amine
pumps
References:
1. “Advanced HCR targets zero sulfur emissions,” Sulphur, Nov-Dec 2011.
2. Micucci, L., “Optimize Claus operations,” Hydrocarbon Processing,
December 2005.
3. “Operating Claus plants off ratio,” Sulphur, July-August 2004.
4. “H2S recovery from Claus tail gas treatment and liquid sulphur degassing,”
Refining China conference, 2016.
Licensor: Siirtec Nigi S.p.A.—Process Department
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Contact: marketing@siirtecnigi.com
Installations: More than 35 HCR plants have been designed, with capacities ranging
from 1.5 tpd–340 tpd. Approximately 70% have been put into operation worldwide.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—Integrated Claus
Application: Debottlenecking of an ammonia Claus unit (or brand new unit)
for treating a larger quantity of ammonia (NH3 )-bearing streams, while assuring
very stringent environmental requirements for both offgas and wastewater.
Description: The process allows for the treating of very-high NH3 content in the
sour water, overshooting the usual limitation of NH3 /hydrogen sulfide (H2S) ratio
in the feedstock to Claus. The process is comprised of high-pressure and low-pressure
sour water stripper (SWS) units, sulfur recovery units (SRUs) and a special integrated
thermal oxidizer:
1. Stripping the wastewater using high pressure to produce a gaseous overhead
stream containing only H2S and water, and a liquid-bottom stream essentially
containing aqueous NH3 .
2. Stripping the bottom liquid in a 2nd stage at low pressure to produce a gaseous
overhead stream of pure NH3 and a liquid-bottom stream containing less than
1 ppm of H2S and less than 5 ppm of NH3 . Consequently, the water can be
discharged into the sewer in full compliance with EU directives.
3. NH3-rich gas is thermally oxidized into nitrogen and water in the special thermal
oxidation unit to produce an outlet stream containing less than 1 ppm in volume
of NH3 and 80 mg/Nm3–150 mg/Nm3 in volume of nitrogen oxides (NOx).
4. Thermal oxidation of the Claus off-gas and the effluent from the NH3 incinerator.
Pure NH3
SW
HP stripper
LP stripper
NH3 thermal oxidier
Stripped water spec:
H2S < 1 ppmw;
NH3 < 5 ppmw
SRU
Thermal oxidizer
Pure H2S
To Atm
NOx < 150 mg/Nm3
Operating conditions: In all cases, when NH3 content is over the limits
for ammonia Claus.
References:
“Sulfur recovery unit integrated with dual-stage sour water stripper and
incinerator section featuring ammonia destruction—a project case,”
Sulphur 2015: 31st Annual Conference of Sulphur and Sulphuric Acid, Toronto,
Ontario, Canada, November 9–12, 2015.
Yields: As per the standard Claus process
Licensor: Siirtec Nigi S.p.A.—Process Department
Advantages: The possibility to treat sour water that is highly rich in NH3
to adhere to stringent environmental requirements.
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Investment: High cost with respect to all other ammonia treating solutions
Contact: marketing@siirtecnigi.com
Utilities: Steam consumption
Development/Delivery: Siirtec Nigi’s R&D department achievement
Installations: European refineries
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—Modified Claus
Application: Convert hydrogen sulfide (H2S) in acid-gas streams to elemental sulfur
using the modified Claus process. This process may be used in natural gas plants,
petroleum refineries and other processes from which H2S is a byproduct.
Description: Acid-gas streams from an amine regenerator (A) and (if applicable) a
sour-water stripper (B) are fed to the proprietary sulfur recovery unit (SRU), acid gas
injector (1) and two-zone thermal reactor (2), where one-third of the H2S is converted
to sulfur dioxide (SO2 ). Elemental sulfur forms from the reaction between H2S and SO2.
Combustion air is provided by an air blower (9). Ammonia in the sour water stripper
(SWS) gas is destroyed in the thermal reactor at > 2,300°F front-zone temperature,
which is adjusted via a bypass of a portion of amine acid gas to the rear zone.
Heat from the thermal reactor effluent is recovered in a waste-heat boiler (3). The
gas stream is then raised to the optimum reaction temperature in reheat exchangers
(5), and the H2S and SO2 react to form sulfur and water vapor in two or three catalytic
reactors (6) in series. Sulfur vapor is condensed in sulfur condensers (4 and 7), and the
liquid sulfur flows to storage through sulfur seals (8). Tail gas (D) from the SRU usually
passes to a tail gas treating unit to increase overall sulfur recovery efficiency.
Operating conditions: Key control variables are the air-to-feed ratio, reactor inlet
temperatures, and the thermal reactor front-zone temperature.
5
To tail gas
treating unit
D
6
7
Amine acid gas
A
4
SWS acid gas
B
Steam
8
C
Air
9
1
3
2
Sulfur
Yields: Typical sulfur recovery efficiency in a three-catalytic bed SRU is 97%–98%.
Advantages: Robust, safe, proven process and equipment designs enable
4 yr–5 yr run lengths.
Economics:
Investment: Capacity basis from 25 ltpd–300 ltpd (long ton per day) sulfur,
1Q 2017, US Gulf Coast (USGC), 103$/ltpd 105–430.
Utilities: Typical per long ton of sulfur produced
Electricity, kWh
100
Steam (exports at 50 psig and 600 psig), lb
6,500
Cooling water circulation, gal
0–5
Fuel
0
Development/Delivery: Ongoing incremental improvements are made based on
operating experiences and improved catalysts, instrumentation and safety features.
Installations: More than 150 units are installed worldwide with a capacity of more
than 15 Mltpd.
References:
1. Handbook of Petroleum Refining Processes, 4th Ed. pp. 537–563, McGraw-Hill,
2016.
2. Kafesjian, A. S., “Case study—multi-faceted SRU upgrade,” Sulphur 2013,
Miami, Florida, November 2013.
3. Kafesjian, A. S., “Improved acid gas burner design debuts in major European
refinery upgrade,” IDTC 2013, Dubrovnik, Croatia, May 2013.
4. “Peak operating, environmental performance with sulfur recovery technology,”
Hydrocarbon Processing, Sulfur 2011, May 2011.
Licensor: Amec Foster Wheeler
Website: www.amecfw.com
Contact: Sulfur@amecfw.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—SCOT®
(Shell Claus off-gas treatment)
Application: Shell sulfur recovery processes are applicable for the conversion of
hydrogen sulfide (H2S) in acid gas streams to elemental sulfur through the modified
Claus process. The Claus unit converts H2S to sulfur, and it can be targeted to combust
hydrocarbons and other contaminants effectively. It is designed to work in conjunction
with the SCOT process, and can be applied in combination with other processes at
refineries and gas plants aiming for ultra-high sulfur recoveries.
Description: The SCOT process is intended for > 5 t/d sulfur removal operation. It uses
an amine solvent to recycle H2S to the Claus unit after it converts the sulfur from the
Claus tail gas to H2S. It is also available in a low-temperature (SCOT LT) application
(< 240°C) and offers high sulfur conversion of > 99.8%. Early in 2017, Shell launched
the SCOT ULTRA process, the next-generation SCOT process. It offers the following
benefits relative to formulated methyl diethanolamine and uses the new-generation
SCOT catalyst C-834 supplied by Criterion Catalyst & Technologies:
• New-generation, selective solvent that maximizes carbon dioxide (CO2 )
slippage, selectively removes H2S and absorbs better at higher temperatures
• Improved tolerance to upsets
• Better environmental performance: < 150 ppm sulfur dioxide (SO2 )
• Increased capacity (debottlenecking option)
• Lower CAPEX (greenfield applications)
• Lower OPEX (green- and brownfield applications).
The Claus tail gas feed to the SCOT unit is heated to 220°C–280°C using an inline
burner or a heat exchanger, with optionally added hydrogen (H2 ) or a mixture of
H2 and carbon monoxide (CO). The heated gas then flows through a catalyst bed,
where sulfur components, SO2 , elemental sulfur, carbonyl sulfide and carbon
disulfide are converted to H2S. The gas is routed through a water-quench column.
This is followed by selective H2S removal in an amine absorber: potentially down to
10 ppmv H2S, depending on the conditions and type of solvent applied. The absorbed
H2S is recycled to the Claus unit via the amine regenerator. The absorber off-gas
is incinerated. The process is continuous, has a pressure drop of 4 psi or lower,
provides excellent sulfur recovery and can be operated with high reliability.
Advantages: SCOT technology enables the achievement of very high levels of sulfur
recovery and very low levels of SO2 emissions, and is a key process for fulfilling
increasingly stringent emissions specifications, including the most exacting World
Bank standards.
SRU tail gas
Offgas to
incinerator
Heater
Reactor
MPS
30 bar
435 psi
Steam
Quench
column
Absorber
Stripper
Steam
Heat recovery
unit
Condensate to
sour-water stripper
Other benefits include:
• High flexibility: The process can operate over a wide range of sulfur intakes,
and a turndown ratio of less than 10% of design throughput is achievable
• Low maintenance requirements: requires little operational attention
• Excellent reliability: less than 1% unscheduled downtime has been achieved
in Shell-advised units
• Lower CO emissions
• Good tolerance to incomplete ammonia destruction in the upstream Claus unit.
• No troublesome secondary waste streams.
SCOT ULTRA
• New-generation, selective solvent that maximizes CO2 slippage, selectively
removes H2S and absorbs better at higher temperatures
• Improved tolerance to upsets (excellent resilience to H2S spikes)
• Better environmental performance: ultra-low SO2 emissions levels
achievable (< 150 mg/Nm3 )
• Increased capacity (debottlenecking option)
• Lower CAPEX (greenfield applications)
• Lower OPEX (green- and brownfield applications).
Continued 
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COMPANY INDEX
Desulfurization—SCOT® (Shell Claus off-gas treatment) (cont.)
Development/Delivery: Shell is both an operator and licensor, which leads to
optimized design margins and applied lessons. Shell has more than 60 years
of licensing experience, more than 100 years of operational experience and
in-house-developed processes.
Installations: The SCOT process was developed in the early 1970s, and is the
industry’s most widely selected tail gas cleanup process. More than 250 units
have been licensed and are in operation or under construction worldwide
in refineries and gas, liquefied natural gas (LNG) and chemical plants.
References:
1. Bowerbank, G. and P. Chilukuri, “Why choose a one-size-fits-all tail gas treating
unit?” Middle East Sulphur, February 2017.
2. Leene, G., “Getting to grips with sulphur recovery units,” Impact, Iss. 2, 2014.
3. Desai, P., “Meeting tough limits: Advanced sulphur removal technologies applied
at PDVSA facilities in Venezuela,” Impact, Iss. 2, 2013.
4. Kohlbrugge, A., “Controlling emissions during SRU start-ups,” Sulphur Magazine,
July 2013.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
2017 REFINING PROCESSES HANDBOOK
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Desulfurization—Shell sulfur
degassing
Air blower
Application: Shell sulfur recovery processes are applicable for converting
hydrogen sulfide (H2S) in acid gas streams to elemental sulfur through the modified
Claus process. They can be applied in combination with other processes at refineries
and gas plants aiming for ultra-high sulfur recoveries. As well as conventional
sulfur recovery processes, Shell has several pioneering sulfur recovery processes,
each with their own applications
Description: The Shell sulfur degassing process reduces H2S and hydrogen
polysulfide in liquid sulfur coming from the Claus unit. To meet environmental and
safety restrictions, the liquid sulfur should be degassed down to less than 10 ppmw
H2S. Sulfur from the Claus unit is run down into either a concrete pit or a steel vessel,
and subsequently circulated over a stripping (bubble) column by bubbling air through
the sulfur. By agitating the sulfur in this way, H2S is released. Sweep air is passed
over the top of the sulfur to remove released H2S. The vent gases can be either sent
to an incinerator or can be recycled to the Claus unit to boost sulfur recovery
efficiency. The degassed sulfur is then pumped to storage. The major advantage
of the Shell sulfur degassing process is that there are no moving parts and no catalyst
is required, so it is easy to operate.
Advantages:
• No moving parts
• No catalyst involved
• Simple and easy to operate
• Straightforward approach to tighter SO2 emissions by recycling vent gas.
Development/Delivery: Shell is both an operator and licensor, which leads to
optimized design margins and applied lessons. Shell has more than 60 years of
licensing experience, more than 100 years of operational experience and in-housedeveloped processes.
Installations: There are presently more than 350 Shell sulfur degassing units in
operation, with capacities ranging from 3 tpd to 4,000 tpd of sulfur.
Vent air to Claus main burner gun
Air
Bubble
columns
Sulfur vessel
Sulfur degassing
vessel
Sulfur to storage
Liquid sulfur from
sulfur locks
References:
1. Demmer, A. and P. Chilukuri, P., “Cost-effective and innovative emissions
reduction configurations in sulphur recovery and tail gas treating units”
SOGAT conference, March 2017.
2. Singoredjo, L. and S. Pontfoort, “Sulphur degassing process,” Sulphur Magazine,
May 2015.
3. Janssen, R. and S Pontfoort, “Shell pressurized sulphur degasser,”
Sulphur conference, November 2015.
4. van den Brand, K., “Under pressure: How operating the Shell Sulphur degasser at
pressure can substantially cut emissions and enhance safety,” Impact, Iss. 3, 2012.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Desulfurization—Sour Water Treating
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers
a complete suite of sulfur block technologies, including sour water treating.
A sour water stripper (SWS) boils off hydrogen sulfide (H2S), ammonia (NH3 ),
carbon dioxide (CO2 ) contaminants, and contaminant hydrocarbons such as
acid gas, to produce stripped water.
The sour water from refinery water washes (crude distillation, desalters,
cokers, hydrotreaters, hydrocrackers, etc.) must be treated before discharge
or reuse. Often, two SWS units are used for phenolic and non-phenolic sour water
to recover partially purified overhead gases when NH3 is commercially valuable
(see WWT Ammonia Recovery).
Description: Typical sour water is saturated with hydrocarbons, so it is flashed
to about 5 psig (or flare header pressure) (1) to remove entrained hydrocarbons and
allow phase separation from light hydrocarbons. Flashed vapors are flared or
recovered by a wet gas compressor. Recovered hydrocarbon liquids are sent
to the refinery slop-oil system.
The sour water is then pumped (2) to the sour water feed preparation tank
(3), which is typically sized for 5 days’ residence time, for further hydrocarbon
separation and removal, and to stabilize the contaminant concentrations.
The sour water is then pumped (4) through a filtration system (not shown)
to remove particulates to minimize downstream erosion, fouling and loss of
performance, before being pre-heated (5). Sour water then enters the SWS (6),
where the reboiler (9) uses LP steam to boil off contaminant gases.
Typical strippers condense overhead gas and return liquids as reflux, but in
an SWS, this phase change of H2S, NH3, and CO2 causes severe corrosion. Amine
regenerators do not have this problem because these compounds are chemically
bound to the amine. Instead, liquid from a tray above the feed tray is pumped (7)
through the overhead cooler (8) and back to the top tray in a “pump-around loop,”
to maintain the overhead gas temperature above the deposition point of ammonium
polysulfide salts (170°F–180°F).
From the SWS bottoms, the stripped water is pre-cooled (5) and pumped (10)
through the stripped-water coolers (11), which can be a combination of air- and
water-cooled exchangers, out to the battery limits.
(11)
Stripped water
SWS acid gas
(10)
(8)
(5)
(6)
Sour water feed
(1)
(2)
(7)
(9)
(3)
LP steam
(4)
Utilities: typical per gal feed
Electricity, kWh
Steam (LP), lb/gal of water
Water, cooling (25°F), gpm
Fuel (absorbed), Btu
0.002
1.5
7.2
0
Installations: This process has been used in thousands of units worldwide
to produce low-ammonia and low-sulfur process streams.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
Advantages: Bechtel’s SWS units can reduce contaminant acid gases to the typical
client specifications of 10 ppmw to 50 ppmw NH3 , and < 10 to < 1 ppmw H2S or lower,
which is suitable for reuse or discharge.
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2017 REFINING PROCESSES HANDBOOK
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Desulfurization—SRU, TGT and Degas
Application
Recovery of sulfur from acid gas streams containing hydrogen sulfide (H2S).
Feedstocks are acid gases from sweetening units and sour water strippers.
Product is bright yellow sulfur with up to 99.9% purity, with no coproducts.
Description
Acid gases are burnt sub-stoichiometrically with air in a refractory-lined furnace.
The resulting mixture of H2S and SO2 reacts to form elemental sulfur, which is removed
from the process through condensation. In subsequent catalytic stages, typically
two or three, the conversion to sulfur is promoted, further yielding a sulfur recovery
of 94.5%–97.5% for the Claus unit.
Two tail gas treatment (TGT) options are available to boost the sulfur recovery
further:
1. SulfreenTM: A catalytic purification of the Claus tail gas for an overall sulfur
recovery up to 99.5%.
2. LTGTTM: Claus tail gas is purified in a wet scrubbing process. Due to
the recycling of the H2S-rich stream to the Claus unit, total sulfur recovery
can be increased to 99.9%.
In the degassing section, the H2S content of the liquid sulfur is decreased to
a maximum of 10 ppm. The catalytically promoted AquisulfTM technology or the
catalyst-free DegasulfTM technology can be used. Offgas from TGT and degassing
is incinerated.
Economics
Sulfur recovery: > 95%
Operating costs can be considered negligible if credit is given for steam produced
in the sulfur recovery unit.
CAPEX: 10 to 100MM $USD, up to 1,000 tpd
Acid gas
SWS gas
Flue gas
Claus tail gas
Claus
Offgas
TGT (LTGT™ or Sulfreen™)
Sulfur
Degassing
(Aquisulf or Degassulf)
Incineration
Offgas
Sulfur
Licensor
Air Liquide Engineering & Construction AquisulfTM is a trademark
of Elf Aquitane
Installations
> 170 Claus plants (4 tpd–1,000 tpd)
> 60 TGT processes
> 50 Aquisulf units in operation
Website
www.engineering-airliquide.com/sulfur
Contact
sulfur@airliquide.com
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Desulfurization—Sulfur Degassing
Steam ejector
Application: Remove hydrogen sulfide (H2S) and hydrogen polysulfides (H2Sx )
dissolved in liquid sulfur.
Description: Liquid sulfur flowing from the Claus plant to the sulfur pit contains
250 ppmw–350 ppmw of H2S and H2Sx . Sulfur is degassed using specific masstransfer equipment to release dissolved gas. Sulfur from the pit is pumped into
the degassing tower, where it is contacted with a mixture of air and steam over
the mass-transfer device. Stripping air promotes the decomposition of H2Sx and
releases the dissolved H2S. Degassed sulfur is routed to the product section of
the sulfur pit. The material for construction is mainly concrete, with internals
comprised of stainless steel. The addition of chemicals is not required.
Sweep air
LS
Air
Degassing box
LS
Liquid sulfur
Degassed sulfur
LS
Air inlet
Sulfur pump
LC
Operating conditions: Treated sulfur has a residual H2S level in the range of
5 ppmw–10 ppmw.
Yields: Not applicable
Advantages: Easy maintenance, low installation cost
LS
LC
Sulfur pit
LC
LS
Investment: The capital cost is in the range of 10% of the cost of a two-reactor
Claus unit.
Utilities: Steam and compressed air
Development/delivery: Internal development
Installations: Siirtec Nigi has designed more than 30 units, and more than 10 have
been put in operation. Siirtec Nigi has recently licensed two European refineries with a
170,000 tpd and a 160,000 tpd sulfur degassing units.
Licensor: Siirtec Nigi S.p.A.—Process Department
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Contact: marketing@siirtecnigi.com
References:
1. “Making sulphur safer,” Sulphur, May-June 2015.
2. “High sulphur recovery rate plus near zero-emissions with HCR and enhanced
sulphur degassing system,” Bottom of the Barrel Technology Conference Middle
East and Africa, 2015.
3. “H2S recovery from Claus tail gas treatment and liquid sulphur degassing,”
Refining China conference, 2006.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Desulfurization—Sulfur RecoveryOxynator™/OxyClaus™
Application
Oxygen enriched Sulfur Recovery Unit (SRU) for oxygen enriched SRU operation
for CAPEX (plot space savings for new SRU) and SRU revamps and debottlenecking.
Feedstock is acid gases and oxygen. Product is bright yellow sulfur up to 99.9% purity,
with no co-products.
Description
Units available for up to 1,000 tpd of sulfur capacity.
In a conventional Sulfur Recovery Unit ambient air is used to oxidise part of the
hydrogen sulfide (H2S) in the acid gases to sulfur dioxide (S02). By enriching the
combustion air to the Claus unit with pure oxygen more feed gas can be processed in
the SRU without violation of pressure drop or residence time constraints. Air Liquide
Engineering & Construction provides the most suited oxygen enrichment technology
depending on client’s requirements.
Oxynator for low-level enrichment (<28% 02 in air)
Low-level oxygen enrichment is a very cost effective option to increase SRU
capacity up to 125% as there is usually no modification required on existing SRU
equipment. Air Liquide uses its patented Oxynator, a compact swirl type mixer, for
safe and efficient oxygen mixing. The pure oxygen is mixed into the combustion air of
the Claus unit upstream the Claus burner.
OxyClaus for high-level enrichment (<60% 02 in air)
Capacity increase to 200% can be achieved by using the well known Lurgi
OxyClaus process that can safely handle high levels of oxygen. In the specially
designed Lurgi OxyClaus burner the oxygen is directly injected into the flame via
dedicated oxygen lances. The hot oxygen flame is surrounded by a cooler acid gas —
air flame shielding the refractory from exposure to high temperature.
SWS gas
Acid gas
Oxygen
Claus tail gas
Thermal stage
Catalytic stage 1
Catalytic stage 2
Sulfur
Installations
More than 40 units in operation.
Website
https://www.engineering-airliquide.com/sulfur
Contact
sulfur@airliquide.com
Advantages
Integration with ASU, low power consumption, pre-assembled packages or skid
units to ease the erection.
Economics
OPEX: Pure oxygen requirement: Approx. 0.15 to 0.4 ton oxygen / ton sulfur
(depending onenrichment level and feed gas composition.
CAPEX: Oxynator: minor investment. Oxyclaus: Approx. 35% TIC savings
for new units
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Desulfurization—S Zorb™ SRT
Application: The S Zorb sulfur removal technology (SRT) is designed to remove
sulfur from full-range naphtha, from as high as 2,000 μg/g of feed sulfur to as low
as < 10 μg/g product sulfur. This technology is a one-step process with high-liquid
yield and high-octane number retention.
Description: Originally developed and commercialized by Phillips Petroleum Co.
(now ConocoPhillips), S Zorb SRT was the first industrial adsorptive desulfurization
technology used for removing sulfur in fuel oil. SINOPEC purchased the ownership
of the S Zorb sulfur removal suite of technologies in July 2007.
Advantages: S Zorb SRT differs from hydrodesulfurization (HDS) technologies.
This differentiation includes:
• High-octane number retention (especially for reducing > 1,000 μg/g feed sulfur
to < 10 μg/g product sulfur in one step)
• High selectivity and reactivity toward all sulfur-containing species
for S Zorb sorbent
• Adapts to full-range naphtha
• Low-net hydrogen (H2 ) consumption and low-H2 feed purity needed; thus,
reformer H2 is an acceptable H2 source
• Low-energy consumption due to no presplitting of fluid catalytic cracker (FCC)
feed stream, and full-range naphtha is applicable
• High-liquid yield (more than 99.7 v% in most cases)
• Regenerated sorbent, with sustained stable activity, to allow the synchronization
of the maintenance schedule with the FCCU.
Installations: More than 40 units have been installed globally, with a total capacity of
approximately 40 MMtpy. The largest unit installed has a total capacity of 2.4 MMtpy.
References:
1. Li, W., “S zorb sulfur removal technology—a solution for Tier 3,” AIChE Spring
Meeting and Global Congress on Process Safety, April 2015.
2. Qi, W., X. Ji, Y. Hou and Z. Qin, “Study on reduction of octane number loss
of gasoline in S Zorb unit and practice,” Petroleum Refinery Engineering,
Vol. 11, 2014.
3. Wei, H., “S-zorb adsorbent and technological advances,” Sino-Global Energy,
No. 3, 2013.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
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Desulfurization—Tail gas treating
Application: Convert residual sulfur compounds in sulfur recovery unit (SRU)
tail gas into hydrogen sulfide (H2S); recover and recycle the H2S to the SRU
to increase overall sulfur recovery efficiency.
Description: Tail gas (A) from the SRU is heated using high-pressure steam and
combined with hydrogen (H2 ) (B), and then all sulfur compounds are reacted
to H2S over low-temperature open-art Co/Mo catalyst in the tail gas reactor (1).
Heat generated in the reactor is recovered from the reactor effluent stream in
a waste-heat boiler (2). The reactor effluent is further cooled in the quench column
(3) before entering the methyldiethanolamine (MDEA) absorber (4), in which
nearly all H2S is removed from the gas. The overhead stream (C) from the absorber
is sent to the incinerator/stack before release to the atmosphere. H2S is removed
from the MDEA in the regenerator (5), and the resulting H2S-rich overhead stream
(D) is recycled to the SRU. Particulate filters and carbon adsorption are included
to maintain MDEA cleanliness.
Alternate design features:
• Reactor feed/effluent exchanger can be added to reduce steam consumption
• Low-cost option uses “shared” MDEA to eliminate the regenerator
and associated equipment
• Reducing gas generator can be included if H2 is not available
• Use of formulated MDEA offers performance advantages.
Operating conditions: Key control variables are the H2 addition rate, reactor inlet
temperature, lean amine temperature and lean amine H2 S loading.
Yields: Typical atmospheric emission of sulfur dioxide (SO2 ) after incineration
of absorber overhead is less than 150 ppmv. Lower SO2 emissions can be achieved
using upgraded equipment design or special MDEA formulations. Adding a tail-gas
treating unit to an SRU can increase overall sulfur recovery to greater than 99.98%.
Advantages: Robust, safe, proven process and equipment designs enable
4 yr–5 yr run lengths.
Economics:
Investment: For an associated SRU with capacity basis from 25 ltpd–300 ltpd
(long ton per day) sulfur, 1Q 2017, US Gulf Coast (USGC), 103$/ltpd 100–420.
Recycle
to SRU
B
A
Incinerator
and stack
H2
SRU tail gas
D
C
1
3
2
5
4
Utilities: Typical consumptions per lt sulfur (SRU basis)
Electricity, kWh
75
Steam (600 psig import), lb
50
Fuel, MMBtu (for incineration)
3.3
H2, scf
1,700
The above is based on air cooling; supplemental water cooling may be required
depending on processing objectives.
Development/Delivery: Ongoing incremental improvements are made based on
operating experiences and improved catalysts, instrumentation and safety features.
Installations: More than 40 units are installed worldwide.
References:
1. Encyclopedia of Chemical Processing and Design, Vol. 56, pp. 294–310,
Marcel-Dekker, 1997.
2. “Peak operating, environmental performance with sulfur recovery technology,”
Hydrocarbon Processing, Sulfur 2011, May 2011.
Licensor: Amec Foster Wheeler
Website: www.amecfw.com
Contact: Sulfur@amecfw.com
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Desulfurization—Thiopaq O&G
Gas out
Application: Shell sulfur recovery processes are applicable for converting hydrogen
sulfide (H2S) in acid gas streams to elemental sulfur through the modified Claus process.
They can be applied in combination with other processes at refineries and gas plants
aiming for ultra-high sulfur recoveries. As well as conventional sulfur recovery processes,
Shell has several pioneering sulfur recovery processes, each with their own applications.
Description: The Thiopaq O&G process is biological desulfurization of natural gas,
synthesis gas, associated gas and Claus tail gas, with 0.5 tpd–70 tpd sulfur removal.
Aqueous soda solution containing sulfur bacteria is applied to biologically remove H2S
from gas streams and recover H2S as elemental sulfur. Relative to the first generation
Thiopaq O&G process, this generation shows the following benefits:
• Decreased plot space
• Fewer bioreactors for large plants and consequent lower CAPEX
• For small plants (up to 5 tpd of sulfur), aerated tanks of glass-fiber-reinforced
material rather than Circox reactors (stainless steel, more complicated
internals) can be installed for lower CAPEX
• Lower caustic consumption
• Less bleed production.
The Thiopaq O&G process can be designed to treat gas streams down to
less than 4 ppmv H2S under pressures greater than 4 bar, and down to 25 ppmv
H2S under pressures below 4 bar. The H2S removal efficiency is above 99.99%.
The biosulfur produced can be used directly as fertilizer, as it has a hydrophilic
character. Owing to the small particle size, the sulfur is more accessible in the soil
for oxidation and subsequent uptake by plants as sulfate. Alternatively, the biosulfur
can be washed and melted to produce a liquid sulfur product that will meet industrial
specifications. The hydrophilic character is lost after melting.
In the Thiopaq O&G process, H2S is directly oxidized to elemental sulfur using
thiobacillus bacteria. These naturally occurring bacteria are not genetically modified.
Feed gas is sent to a caustic scrubber in which the H2S reacts to sulfide. The sulfide is
converted to elemental sulfur and caustic by the bacteria. Sulfur particles are covered
with a (bio-)macropolymer layer that keeps the sulfur in a suspension that does not
cause fouling or plugging. In this process, a sulfur slurry is produced that can be
concentrated to a cake containing 60% dry matter. This cake can be used directly
for agricultural purposes or as feedstock for H2S manufacturing. Alternatively, the
biological sulfur slurry can be purified further by melting to high-quality sulfur to
meet international Claus sulfur specifications, or it can be processed to high-quality
agricultural products.
Vent
NaOH
Nutrients
Water
Flash gas
Gas in
Bleed
Sulfur
Air
Absorption
section
Fash vessel
(optional)
Reactor
section
Sulfur recovery
section
Advantages: Depending on the sulfur tonnage and H2S/carbon dioxide (CO2 ) ratio,
the Thiopaq O&G process can be very cost competitive relative to conventional sulfur
recovery technologies, and brings most value for lean acid gases, i.e., < 45 vol% H2S.
Compared with the first-generation units, the latest generation of Thiopaq O&G
technology brings the following additional benefits:
• Less plot space
• Fewer bioreactors for large plants and, consequently, lower CAPEX
• For small plants (up to 5 t/d of sulfur), aerated tanks of glass-fiber-reinforced
material rather than CIRCOX® reactors (stainless steel, more complicated
internals) can be installed for lower CAPEX
• Lower caustic consumption
• Less bleed production.
Development/Delivery: Shell is both an operator and licensor, which leads to
optimized design margins and applied lessons. Shell has more than 60 years of
licensing experience, more than 100 years of operational experience and in-housedeveloped processes.
Continued 
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Desulfurization—Thiopaq O&G (cont.)
Installations: The first Thiopaq O&G unit started up in 1993, and the process has been
licensed since 2000. There are 15 Thiopaq O&G units in operation and another seven
are in the start up, construction or design phase. These units have capacities ranging
from 1 tpd to 50 tpd of sulfur, but, with continuing research and development, this
window is increasing year-on-year.
References:
1. Klok, J., G. van Heeringen, R. de Rink, P Hauwer and G. Bowerbank,
“Techno-economic impact of the next generation of the Thiopaq O&G
process for sulphur removal,” SOGAT, March 2017.
2. Bowerbank, G. and P. Chilukuri, “Why choose a one-size-fits-all tail gas treating
unit?” Middle East Sulphur, February 2017.
3. Engert, T. and H. Wijnbelt, “Turning sour casing head gas into profits,”
Sulphur Magazine, March 2014.
4. Wijnbelt, H., “Harnessing the power of nature: Innovative biological gas
desulphurisation process offers various benefits” Impact, Iss. 3, 2012.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
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Desulfurization—
WWT Ammonia Recovery
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers a
complete suite of sulfur block technologies, including the specialized WWT ammonia
recovery unit.
Sour water from refinery water washes (crude distillation, desalters, cokers,
hydrotreaters, hydrocrackers, etc.) must be treated before discharge or reuse.
WWT splits sour water into three streams: nearly pure ammonia (NH3 ) with hydrogen
sulfide (H2S) in the ppm range; nearly pure H2S with NH3 in the ppm range; and
stripped water that meets client specification for discharge to the wastewater system
of 10 ppmw to 50 ppmw NH3, and < 10 ppmw to < 1 ppmw H2S.
Description: Typical sour water is saturated with hydrocarbons, so it is flashed to about
5 psig (or flare header pressure) (1) to remove entrained hydrocarbons and allow phase
separation from light hydrocarbons. Flashed vapors are flared or recovered by a wet
gas compressor. Recovered hydrocarbon liquids are sent to the refinery slop-oil system.
The sour water is then pumped (2) to the sour water feed preparation tank (3),
typically sized for five days’ residence time, for further hydrocarbon separation and
removal, and to stabilize the contaminant concentrations.
The sour water is then pumped (4) through a filtration system (not shown) to
remove particulates to minimize downstream erosion, fouling and loss of performance,
before being pre-heated (5). Sour water then enters the H2S stripper (6), where the
reboiler (7) uses steam to boil off contaminant gases, and a water wash removes NH3
from the H2S gas. The H2S stripper bottoms then flow to the NH3 stripper (9).
The NH3 stripper overhead gas is cooled (11), and reflux is recovered (12) and
pumped (13) back to the tower. From the NH3 stripper bottoms, the stripped water is
pumped (14) through a cross-exchanger (5) and cooler (15) out to the battery limits.
The NH3 gas stream from the reflux drum (12) is then cleaned up in the NH3
cleanup system (16) to remove H2S, water and other contaminants, which are recycled.
The cleanup system liquefies the NH3 as either anhydrous ammonia or an aqueous
ammonia product. Concentrations are specified by the client.
Advantages: Bechtel’s WWT ammonia recovery unit benefits from:
• Revenue from the sale of NH3, with a simple payout time of 3 to 7 years
• HP and LP steam production from NH3 incineration
• Expanded sulfur recovery unit (SRU) capacity by 3 tons of sulfur per ton of NH3
removed
• No new SRU incinerator air permit needed if anhydrous ammonia is made.
Hydrogen sulfide
Recycle
Stripped water
(16)
(11)
(8)
(15)
Sour
water
(12)
NH3 cleanup
Ammonia
CW
(1)
(5)
(3)
(2)
(9)
(6)
(13)
(4)
Steam
Steam
(7)
(10)
(14)
Utilities: Typical per gal feed:
Electricity, kWh
Steam, lb/gal water
Water, cooling (25°F), gpm
Fuel (absorbed), Btu
0.040
5.4
30
0
Installations: This process has been used worldwide to produce low-ammonia
and low-sulfur process streams.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
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Distillation—Crude and
vacuum distillation
Application: The Shell crude distillation–vacuum distillation process is a highlyintegrated design applied successfully at many Shell and third-party refineries.
The process separates crude into short residue, heavy-vacuum gasoil (HVGO),
middle distillates and a naphtha minus fraction. Compared with stand-alone units,
the overall integration of a crude distillation unit (CDU), a hydrodesulfurization (HDS)
unit, a high-vacuum unit (HVU) and a visbreaker unit (VBU) results in a 50%
reduction in equipment count and significantly lower operating costs.
A prominent feature in this design is the Shell deep-flash HVU technology. This
technology can be provided in cost-effective process designs
of feed preparation HVUs for hydrocracking units (HCU) and fluidized catalytic
cracking units (FCCU), as well as for lubricant oil HVU. For each application,
tailor-made designs can be produced.
Description: The basic function of the CDU is to separate the naphtha minus and
the long residue from the middle distillate fraction, which is routed to the HDS unit.
The long residue is routed to an HVU, which recovers the VGO fraction from
the long residue as the feedstock for an FCCU or HCU. Typical flash-zone conditions
are 410°C and 22 mbara. The Shell design features a de-entrainment section, spray
sections to obtain a lower flash-zone pressure and a light-vacuum gasoil (LVGO)
recovery section to recover up to 10 wt% as HDS feed. The Shell furnace design
prevents excessive cracking and enables a 5-yr run length before decoking.
Yields: Typical for Arabian light crude
Products
Gas
C1–C4
Gasoline
C5–50°C
Kerosine
150–250°C
Gasoil
250–350°C
VGO
350–370°C
Waxy distillate
370–575°C
Residue
575°C+
wt% (on crude)
0.7
15.2
17.4
18.3
3.6
28.8
16.0
Installation: More than 100 Shell CDUs have been designed and operated since the
early 1900s. Additionally, some 50 HVUs have been built, and a similar number have
been debottlenecked, including many third-party designs for feed preparation and
lubricant oil HVUs.
Fuel gas
Rec
Crude
C
D
U
H
D
F
HDS
Vac
LR
H
V
U
NHT
LPG
Tops
Kerosine
Naphtha
LGO
HGO
VGO
Kerosine
WD
HCU
Storage
VBU
VBU
Flash column
Gasoil
Bleed
Residue
Advantages:
• Regular operational feedback obtained from approximately 25 sites is used
to update databases and design rules, and to provide focus for research areas.
• Best practices are defined based on surveys, technology benchmarking
and gatekeeping.
• Extensive experience with processing difficult crudes, such as high-fouling,
low API and high-TAN crudes, is incorporated in state-of-the art designs.
• An extensive crude oil evaluation database, supplemented with actual
processing experience, enables accurate yield and quality predictions.
• A highly-integrated crude distillation concept incorporating high-performance,
deep-flash vacuum distillation technology is offered.
• The Shell family of high-performance column internals minimizes CAPEX
and OPEX.
• High safety and reliability standards are incorporated in design, engineering
and operational guidelines.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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Distillation—Crude Oil progressive
Application: The crude progressive distillation process minimizes the total energy
consumption required to separate crude oils or condensates into hydrocarbon
cuts. The products are optimized to fit with complex refining schemes. This process
is generally applied to new topping units or integrated topping/vacuum units,
and the concept can be used for revamps.
Products: The process is particularly suitable when more than two naphtha cuts
are to be produced, e.g., in integrated refinery and petrochemical complexes.
Typically, the process is optimized to produce three naphtha cuts or more, one or
two kerosene cuts, two atmospheric gasoil cuts, one vacuum gasoil cut, two vacuum
distillates cuts and one vacuum residue stream.
Description: The crude is preheated and desalted (1). It is first fed to a 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 then fractionated as required in a gas plant and
rectification towers (4). The topped crude, typically reduced by 2/3 of the total
naphtha cut, is then heated in a conventional heater and conventional topping column
(5). If necessary, the reduced crude is fractionated in one deep vacuum column
that is designed for a sharp fractionation between vacuum gasoil, two vacuum
distillates (6) and a vacuum residue, which could also be a road bitumen.
Extensive use of pinch technology minimizes heaters, as well as air and water
cooler duties. The use of latest available equipment technologies (for heat exchangers,
tower internals and vacuum system), and the focus given to furnace and transfer lines
designs, further ensure overall process performance, energy and CAPEX savings.
The process is particularly suitable for large crude capacity, i.e., more than
200,000 bpsd. The process is also available for condensates and light crude
progressive distillation with a slightly adapted scheme.
Economics:
Investment (based on 200,000 bpsd, including atmospheric and vacuum
distillation, gas plant and rectification tower) – $1,700 to $2,300 per bpsd,
depending upon design objectives.
Utility requirements, typical per bbl of crude feed:
Fuel fired, 103 btu
50–65
Power, kWh
0.9–1.2
Steam, 65 psig, lb
0–5
Water cooling, (15°C rise) gal
50–100
LPG
Light naphtha
Feed
4
Medium naphtha
Heavy naphtha
One or two kerosene cut
Stm.
1
2
3
Two kerosene cut
5
Vacuum gas oil
6
Distillate
Distillate for FCC
Vacuum
residue
Total primary energy consumption:
For Arabian Light or Russian Export Blend:
For Arabian Heavy:
1.25 tons of fuel
per 100 tons of crude
1.15 tons of fuel
per 100 tons of crude
Installation: TechnipFMC has completed more than 120 grassroots or revamp
engineering, procurement and construction (EPC) projects, until construction, for
atmospheric and vacuum crude distillation units. The capacity of recent grassroots
units (designed or started in the last 5 yr) ranges from 60,000 bpsd–400,000 bpsd.
A revamp project now in operation using the progressive distillation concept, shows an
increase of crude processing capacity of 30% without heater addition.
Licensor: Total and TechnipFMC
Website: www.technipfmc.com
Contact: alban.sirven@technipfmc.com
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Distillation—Deep-flash,
high-vacuum distillation
Vacuum system
Application: Shell deep-flash, high-vacuum units (HVU) maximize the recovery
of distillate (waxy distillate or vacuum gasoil) from long residue. This fraction has
excellent properties as feedstock for catalytic cracking or hydrocracking units.
A fraction suitable for the refinery diesel pool is also produced. Shell deep-flash
technology has been developed using a combination of comprehensive research
and development and extensive refining experience.
Diesel
Description: Long-residue feed is preheated in a furnace to reach typical flash-zone
conditions of 410°C and 22 mbara. A typical, simplified process flow scheme is shown
here. Shell Global Solutions produces a tailor-made design for each application
in which opportunities for process optimization and integration with other units
are developed.
Yields: Typical for Arab Light crude
Products
Vacuum gasoil
350°C–370°C
Waxy distillate
370°C–575°C
Residue
575°C+
wt% (on atmospheric residue)
7.5
59.5
33.0
Installation: More than 100 Shell crude distillation units that include deep-flash HVU
have been designed and operated since the early 1900s. Additionally,
some 50 HVU have been built, and a similar number have been debottlenecked,
including many third-party designs for feed preparation and lubricant oil HVU.
Advantages:
• The ultra-low pressure drop of the empty spray sections provides a lower flashzone pressure compared with pumparound sections with packing. Typically, this
increases waxy distillate yield by 4 wt% based on the feed to the column.
• The application of empty spray sections lowers the structured packing volume
substantially, which reduces CAPEX and maintenance costs.
• The design features of a Shell deep-flash HVU furnace prevent excessive cracking
and enable a 5-yr run-length before decoking.
• The proprietary feed inlet has a negligible pressure drop, provides good vapor
distribution and is easy to install.
• The design and operational guidelines for the wash-oil bed are based on
operational experience and feedback from more than 25 units advised by
Shell Global Solutions.
Waxy distillate/
vacuum gasoil
Wash-oil bed
Long residue
Vacuum residue/short residue
DWO
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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Distillation—Divided Wall
Column Technology
Application: The separation of multicomponent mixtures in more than two fractions
of substances by replacing sequentially operated columns with a single column,
thus minimizing CAPEX and energy requirements.
Description: The thyssenkrupp divided wall column (DWC) technology is an excellent
tool for optimizing new plants, revamps, enhancing plant capacity and improving
product qualities and yields. Existing columns can be modified within a short
shutdown time, resulting in low production losses. Columns in such configurations
are fully thermal coupled and provide significant energetic advantages over
conventional fractionation technologies. The former proprietor of this technology
was ThyssenKrupp Uhde GmbH.
Economics: Advantages of DWC in comparison to a two-column system
• Up to a 20% reduction in investment costs
• Up to a 35% reduction in energy costs
• Up to a 40% reduction in required plot area.
Installations: Several installations are utilizing thyssenkrupp DWC technology.
A wide variety of DWC’s are implemented in gasoline and aromatic complexes,
such as stabilizer columns, C5/C6/C7+ cut fractionators and BTX separation. The latest
application of thyssenkrupp DWC technology for a reformate splitter unit is now under
construction (2017).
Feed
Product A
Product B
Product C
Special Developments: The DWC technology was successfully applied within
the Morphylane® Aromatic Extractive Distillation technology. The first of its kind
single-column Morphylane plant for the recovery of TDI toluene went onstream
in 2004.
Licensor: The former proprietor of this technology was ThyssenKrupp Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrup.com, dorothe.weimer@thyssenkrupp.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
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Distillation—GT-DWC℠
Application: GT-DWC is an advanced version of distillation that provides better
product specifications with less energy and capital costs in a variety of applications,
including reformate splitting, naphtha splitting, butane, toluene and xylenes (BTX)
extraction, liquefied petroleum gas (LPG)/propylene recovery, etc. The technology
features a proprietary vertical wall that divides the inside of a column into separation
zones. These zones act independently of each other, so independent operations (e.g.,
distillation on one side and absorption on the other) are possible in a single column.
Description: GT-DWC offers highly optimized, unique solutions tailored for specific
applications. As a result, the process flow scheme can vary greatly depending on
the desired results.
The process scheme shown here is for a naphtha splitter column revamp, with
the column using a middle dividing wall. The wall separates the column into two
halves, with the side where the feed enters serving as the pre-fractionation column.
As shown, the lighter boiling components from the feed move to the top of the
column, and the heavier components move to the bottom.
The column’s other side acts as the main fractionation section. The middle boiling
components are concentrated around the center on the other side of the wall and
are removed as heart-cut naphtha product. The overhead vapors at the top of the
column are condensed in an air-cooled condenser and collected in an overhead
receiver. Some of the liquid is sent back to the column as reflux, while the remainder
is routed to the battery limits as light naphtha product.
The liquid from the top half of the column is directed to both sides of the
dividing wall by the use of a proprietary liquid-splitting arrangement. Similarly,
the vapor from the bottom is directed to the two sides of the column to facilitate
better separation of the middle cut.
Advantages:
• High-purity middle product.
• In this particular application, similar product specifications are obtained with
no increase in utilities. In most cases, process utilities are lowered by
approximately 20%–30%,as compared to conventional distillation columns.
• In most applications, the capital costs are reduced by approximately 20%–30%.
• Some DWC applications offer opportunities for heat integration with other
columns, which further reduces utility costs.
• No refrigeration is required in applications involving LPG and propylene recovery.
• DWC technology is applicable for both grassroots and revamp applications.
Light naphtha
Feed
Heart-cut naphtha
Heavy naphtha
Variables
Heart-cut naphtha flowrate
D86 (IBP/FBP)
Naphtha splitter
before revamp
180.4 tph
110.5°C–190.6°C
Naphtha splitter
after revamp
151 tph
110.5°C–172.0°C
Installations: Eight licensed units: four are operational, and four are in the design phase.
References:
1. Bhargava, M., M. Binkley and J. Gentry, “Distillation—then and now,”
Hydrocarbon Processing, August 2016.
2. Bhargava, M., R. Kalita and J. Gentry, “Dividing wall column applications in FCC
splitter columns,” Hydrocarbon Processing, September 2017.
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
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Distillation—Snamprogetti,
Butene-1 recovery, (SP-B1)™
Light ends
Application: The Snamprogetti butene-1 recovery technology (SP-B1) allows the
extraction from a C4 cut of a very high-purity, butene-1 stream that is suitable as a
comonomer for the production of polyethylene.
Feed: Olefinic C4 streams from a steam cracker or fluid catalytic cracking (FCC)
can be used as feedstock for the recovery of butene-1.
Description: The Snamprogetti process for the purification of butene-1 by distillation
is based on proprietary binary interaction parameters, specifically optimized after
experimental work, to minimize investment cost and utilities consumption. The plant
is a super-fractionation unit composed of two fractionation towers provided with
conventional trays.
Depending on the C4 feed composition, SP-B1 offers different possible process
schemes. In a typical configuration, the C4 feed is sent to the first column (1),
where the heavy hydrocarbons (mainly n-butane and butenes-2) are removed
as bottom stream. In the second column (2), the butene-1 is recovered at the bottom
and the light-ends (mainly isobutane) are removed as overhead stream. This kind
of plant covers a wide range of product specifications, including the more challenging
level of butene-1 purities (99.3 wt%–99.6 wt%).
Advantages: The proposed scheme has been developed by keeping in mind the
savings on utilities and the use of standard column trays. In addition, it is able to
receive the C4 stream when the upstream unit is producing ETBE. According to that,
deep heat integration has been applied.
The proposed scheme does not make use of centrifugal compressors, which
results in a lower investment cost, shorter project schedule, maximum reliability, lower
plant complexity, ease of maintenance and lower electric power consumptions. The
integration between etherification and butane-1 units has been proven in a number of
applications.
C4 feed
1
2
Heavy ends
Butene-1
Utilities: Based on a stream with 50% of butene-1
Electricity
65 kWh/t butene-1
Steam, LP
3.4 t/t butene-1
Water, cooling (rise 10°C)
89 m³/t butene-1
Development/delivery: The butene-1 recovery process is based on experimental work
(proprietary binary interaction parameters) performed in the late 1970s in internal
laboratories by Mr. Soave (RKS system developer). The same has been patented.
Installations: Four units have been licensed by Saipem.
Licensor: Saipem S.p.A.
Website: www.saipem.com
Contact: Maura.Brianti@saipem.com
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2017 REFINING PROCESSES HANDBOOK
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Distillation—Vacuum Distillation
Heater
Vacuum tower
Side strippers (optional)
Application: The process produces vacuum distillates that are suitable for lubricating
oil production by downstream units, and as feedstocks to FCC and hydrocracker units.
Description: Feed is preheated in a heat-exchanger train and fed to the fired heater.
The heater outlet temperature is controlled to produce the required quality of vacuum
distillates and residue. Structured packings are typically used as tower internals to
achieve low flash zone pressure and, thus, maximize distillate yields. Circulating reflux
streams enable maximum heat recovery and reduced column diameter.
A wash section immediately above the flash zone ensures that the metals content
in the lowest side draw is minimized. Heavy distillate from the wash trays is recycled to
the heater inlet, or withdrawn as metals cut.
When processing naphthenic residues, a neutralization section may be added to
the fractionator.
To vacuum system
Vacuum gasoil
BFW/STM
STM
BFW
Low visc.
Medium visc.
Feed: Atmospheric bottoms from crude oils (atmospheric residue)
or hydrocracker bottoms.
High visc.
Product: Vacuum distillates of precisely defined viscosities, flash points (for lube
production) and low metals content (for FCC and hydrocracker units), as well as
vacuum residue with specified softening point, penetration and flash point.
Metals cut
Installations: Numerous installations using the thyssenkrupp proprietary technology
are in operation worldwide.
Licensor: The former proprietor of this technology was ThyssenKrupp Uhde GmbH.
Vac. residue
Feed
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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2017 REFINING PROCESSES HANDBOOK
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Ethers—Aerosol DME Process
DME reactor Vaporizer
DME column
Application: The thyssenkrupp dimethyl ether (DME) process catalytically dehydrates
methanol (CH3OH) to produce DME in chemical- or aerosol-grade quality.
Yields: The per-pass conversion of methanol is more than 80%. By recycling
unconverted CH3OH from the distillation section, an overall CH3OH conversion of more
than 98%
is achieved.
Utilities: (per ton of DME)
Electricity
12 kWh
LP steam
600 kg
MP steam
900 kg
Cooling water
85 m³
Offgas
Steam
Description: Feed CH3OH is vaporized, superheated and fed to a tube reactor, where
dehydration occurs exothermally to form DME and water. The reactor temperature
is typically between 270°C–310°C. The reactor effluent is partially condensed and
passed to the DME column. Non-condensable compounds are removed with the vapor
overhead product, which is joined with the vapor overhead product from the CH3OH
column, regarded as offgas. With purity exceeding 99.9 % (chemical grade) or 99.99%
(aerosol grade), DME is withdrawn from the column as a side stream. Excess CH3OH
contained in the bottom product is recovered in the CH3OH column and returned to
the synthesis section. A very small “dirty DME” side stream from the DME column is
applied to remove impurities, such as amines.
Product Utilization: High-purity DME is utilized entirely as a propellant in cosmetic
aerosols, the largest product group being hair sprays. DME-propelled products are
preferred by industry due to their unique properties (e.g., high dissolving power),
their active ingredients and good miscibility with water.
Methanol column
Methanol feed
Waste water
DME product
Impurities
Licensor: The former proprietor of this process was ThyssenKrupp Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
Installations: Five plants for DME production have been installed (including fuel DME).
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Ethers—CDMtbe® and CDEtbe®
Application: To process C4 streams from steam cracker, refinery and isobutane
dehydrogenation units to produce either methyl tertiary butyl ether (MTBE)
or ethyl tertiary butyl ether (ETBE).
Description: MTBE or ETBE is formed by the catalytic etherification of isobutylene
with methanol or ethanol. The patented CDMtbe or CDEtbe process is based on
a two-step reactor design, consisting of a boiling point fixed-bed reactor followed
by final conversion in a catalytic distillation column. The process uses an acidic
ion-exchange resin catalyst in both its fixed-bed reactor and proprietary catalytic
distillation structures.
The unique catalytic distillation column combines reaction and fractionation in
a single unit operation. It allows for a high conversion of isobutylene to be achieved
simply and economically. By using distillation to separate the product from the
reactants, the equilibrium limitation is exceeded and higher conversion of isobutylene
is achieved.
Products: MTBE or ETBE synthesis is a highly selective process for removal of
isobutylene. MTBE synthesis can be used for pretreatment to produce high-purity
butene-1, or for recovery to make high-purity isobutylene via MTBE decomposition.
Process advantages:
Lummus Technology’s catalytic distillation offers:
• Improved kinetics
• High conversion (beyond fixed-bed equilibrium limit)
• Low capital cost
• Low utilities
• Long catalyst life with sustained high conversion
• Reduced plot space.
Fresh wash
Fresh alcohol
Boiling point
reactor
Catalytic
distillation
Alcohol extraction
Recycle alcohol
Alcohol recovery
C4 raffinate
Alcohol
and C4s
Water
Water
Mixed C4s
MTBE or ETBE
Water and
contaminants
Installations: With more than 35 yr of experience, CB&I/Lummus Technology
has licensed more than 130 ethers units.
Licensor: Lummus Technology, a CB&I company
Contact: lummus.tech@cbi.com
Lummus Technology’s boiling point reactor offers:
• Simple and effective control
• Elimination of hot spots
• Long catalyst life
• High flexibility
• Low capital cost
• Elimination of catalyst attrition
• Most effective heat removal technique.
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Ethers—CDTame® and CDTaee®
from refinery C5 feeds
Fresh wash
Fresh alcohol
Application: To process C5 streams from refinery units to produce tertiary amyl
methyl ether (TAME) or tertiary amyl ethyl ether (TAEE).
Description: TAME or TAEE is formed by the catalytic etherification of isoamylene
with methanol or ethanol. The patented CDTame or CDTaee process is based on
a two-step reactor design, consisting of a boiling point fixed-bed reactor followed
by final conversion in a catalytic distillation column. The process utilizes an acidic
ion-exchange resin catalyst in both its fixed-bed reactor and proprietary catalytic
distillation structures.
The unique catalytic distillation column combines reaction and fractionation
in a single unit operation. It allows for a high conversion of isoamylene (exceeding
fixed-bed equilibrium limitations) to be achieved simply and economically. By also
using distillation to separate the product from the reactants, the equilibrium limitation
is exceeded and higher conversion of isoamylene is achieved. Catalytic distillation
also takes advantage of the improved kinetics through increased temperature
without penalizing equilibrium conversion. Advanced process control maximizes
catalyst life and activity to provide high sustained TAME or TAEE production.
Lummus Technology’s ether processes offer:
• Simple and effective control
• Elimination of hot spots
• Long catalyst life
• High flexibility
• Low capital cost
• Elimination of catalyst attrition
• Most effective heat removal technique.
Boiling point
reactor
Catalytic
distillation
Alcohol extraction
Alcohol recovery
Recycle Alcohol
C5 raffinate
Ethanol
and C5s
Water
Water
Mixed C5s
Water and
contaminants
TAME or TAEE
Worldwide Experience: With more than 35 years of experience, CB&I/Lummus
Technology has licensed more than 130 ethers units.
Licensor: Lummus Technology, a CB&I company
Contact: lummus.tech@cbi.com
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2017 REFINING PROCESSES HANDBOOK
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Ethers—ETBE Process
ETBE reactor
Debutanizer
Water wash
Application: The thyssenkrupp ETBE process combines (bio-) ethanol and
isobutene (C4H8 ) to produce the high-octane oxygenate ethyl tert-butyl ether (ETBE).
The process is suitable for processing C4 cuts from steam cracker (SC) and fluid
catalytic cracker (FCC) units with C4H8 contents ranging from 12%–30%.
Yields: For a C4 cut containing 22% isobutene, the isobutene conversion is in excess of
94% at a selectivity to ETBE of 98%.
C4 feedstock
Ethanol
Ethanol (recycle)
Dryer (optional)
Ethanol/water azeotrope
Description: The thyssenkrupp ETBE technology features a two-stage reactor system.
The first reactor is operated in the recycle mode. A slight expansion of the catalyst
bed is achieved, ensuring uniform concentration profiles in the reactor and, most
importantly, avoiding any formation of hot spots. Thus, undesired side reactions—
such as the formation of di-ethyl ether (DEE), and the dimerization or oligomerization
of C4H8 and butadiene (C4H6 )—are minimized.
In ETBE synthesis, water becomes significantly important: water in wet ethanol
inhibits ETBE formation, since the stronger poled water competes against ethanol
in occupying the active centers of the catalyst. For this reason, C4H8 reacts in the
presence of water with priority to tert-butylalcohol (TBA) rather than ETBE. Increased
TBA production, however, not only inflects the rate of ETBE formation, but also the
separation of products in the subsequent distillation and wash sections.
One important subject of the two-stage system is that the catalyst can be
replaced in each reactor separately, without shutting down the ETBE unit. Moreover,
the inlet temperature of both reactors can be easily adjusted between start-of-run and
end-of-run conditions to compensate catalyst deactivation.
The catalyst used in the ETBE process is a cation exchange resin. Isobutene
conversions in the range of 94%–95% are typical for FCC feedstocks, while higher
conversions are reached when processing steam cracker C4 cuts containing isobutene
concentrations of approximately 25%.
ETBE is recovered as the bottoms product of the distillation unit. The ethanol
containing C4 distillate is passed to the ethanol recovery section, where ethanol/
water minimal temperature azeotrope is separated from the pure water phase. If
necessary, in utilization of “wet” feed ethanol, the azeotropic mixture must undertake
an additional drying process prior to recycling to the reactor section. The isobutenedepleted C4 stream may be routed to a raffinate stripper or to a molsieve-based unit
for the removal of oxygenates, such as TBA and ethanol.
Methanol/water
separation
Raffinate 2
ETBE product
Utilities: C4 feed containing 22% isobutene; per metric ton of ETBE
Electricity
35 kWh
MP steam
1,000 kg
LP steam
110 kg
Cooling water
24 m³
Installations: The thyssenkrupp proprietary ETBE process has been successfully
applied in several refineries by retrofitting existing MTBE units for ETBE production
only, or for dual use of MTBE/ETBE production.
Licensor: thyssenkrupp
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com, dorothe.weimer@thyssenkrupp.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Ethers—Fuel DME Process
Application: The thyssenkrupp Fuel DME process catalytically dehydrates methanol
to produce dimethyl ether (DME) in fuel-grade quality.
DME Vaporizer
reactor
DME
column
Methanol column
DME absorber
Offgas
Steam
Description: Methanol is vaporized, superheated and then fed to a fixed-bed reactor
where dehydration occurs exothermally to form DME and water. The reactor inlet
temperature is typically between 260°C–280°C. The reactor effluent is partially
condensed and passed to the DME column. Fuel DME is withdrawn from the column
top. Non-condensable compounds are removed from the overhead product and then
routed to an absorber for DME recovery. Excess methanol contained in the bottom
product is recovered in the methanol column and returned to the synthesis section.
Product Utilization: Fuel-grade DME is used as clean fuel in diesel engines
and as a substitute for petroleum-based liquid gas.
Yields: The per-pass conversion of methanol exceeds 80%. By recycling unconverted
methanol from the distillation section, an overall methanol conversion of
approximately 99.9% is achieved.
Utilities: (Per metric ton of DME)
Electricity
5 kWh
LP steam
300 kg
MP steam
700 kg
Cooling water
60 m³
Waste water
DME product
Installations: Five plants for DME production have been installed (including
Aerosol DME).
Licensor:The former proprietor of this process was ThyssenKrupp Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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Ethers—MTBE/ETBE and TAME/TAEE
Alcohol recycle
Application: Gasoline blending components.
Description: In etherification processes used in refining, methanol (CH3OH) or ethanol
(C2H5OH) reacts with branched olefins in the presence of an acidic ion exchange
resin catalyst to form their corresponding ethers. Reaction conditions are maintained
to minimize undesirable side reactions, e.g., the formation of tertiary butyl alcohols,
water, dimethyl- and diethyl ethers, and di-isobutylenes.
Design configurations applicable to all Axens units include:
• A main reaction section where the major part of the reaction takes place
on an acidic catalyst—fixed-bed reactors or expanded bed reactors may be
used depending upon operating severity
• A fractionation section for separating unconverted raffinate from the
ethers produced
• A finishing reaction section (optional) to enhance conversion
• An alcohol recovery section consisting of a raffinate washing column
and alcohol recovery column for recycling unconverted alcohol to the
main section to improve reaction selectivity (optional in ethanol mode).
Ultimate conversion levels can be achieved by combining the finishing reaction
section and the fractionating into a single distillation column, Catacol™.
Axens also offers cost-effective revamping options to switch from MTBE to ETBE
operating modes, or from TAME to TAEE modes. This revamping strategy covers feed
and product contaminant control, optimization of reaction and distillation sections,
and other options to ensure improved stability and maximized production of ethers.
Advantages:
• High conversion of reactive olefins
• High selectivity (high ether yields with low byproduct formation)
• Use of non-proprietary catalyst
• High catalyst stability
• Easy loading and unloading
• Large operating flexibility, enabling a wide range of feedstock properties
changes.
Economics:
The Axens Etherification Technology Suite offers a large flexibility in terms of:
• Conversion
• Initial CAPEX and OPEX
• CAPEX/OPEX staging.
Fractionator
C4S
C 5S
C6S
C7 S
Finishing
reactor
Raffinate wash alcohol
recovery (optional for TAEE)
Main reactor
section
Raffinate + ether
Alcohol
Ether
A site-specific optimized scheme can be developed, and investment staging
is possible. Typical economics for medium- and high-reactive olefin conversion
etherification units are:
MTBE
ETBE
TAME
TAEE
C4 cut feedstock, tpy
329,000
275,000
369,000 355,000
Investment, $MM
12
10
13
13
Utilities per ton of ether
Electrical power, kWh
18
14
20
20
Steam, tons
1
0.9
1.2
1.2
Cooling water, m3
65
57
73
70
Basis: Gulf Coast unit producing 100,000 tpy of ether from an FCC stream containing
either 20% isobutylene or 20% isoamylenes.
Installations: To date, more than 60 references have been awarded, and more than
45 units are in operation worldwide.
Licensor: Axens
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/
11/etherification.html
Contact: information@axens.net
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Ethers—MTBE Process
MTBE reactor
Debutanizer
Water wash
Application: The thyssenkrupp methyl tertiary butyl ether (MTBE) process combines
methanol (CH3OH) and isobutene (C4H8 ) to produce the high-octane oxygenate
MTBE. The process is suitable for processing C4 cuts from steam cracker (SC) and
fluid catalytic cracker (FCC) units with C4H8 contents ranging from 12%–30%.
By etherification of the reactive C5 olefins, tert-amyl methyl ether (TAME) can
also be produced.
Description: The thyssenkrupp MTBE technology features a two-stage reactor
system. The first reactor is operated in recycle mode. A slight expansion of the catalyst
bed is achieved, ensuring uniform concentration profiles in the reactor and, most
importantly, avoiding any formation of hot spots. Thus, undesired side reactions, such
as the formation of dimethyl ether (DME), are minimized. One important aspect of
the two-stage system is that the catalyst can be replaced in each reactor separately
without shutting down the MTBE unit. Moreover, the inlet temperature of both
reactors can easily be adjusted between start-of-run and end-of-run conditions to
compensate catalyst deactivation.
The catalyst used in the MTBE process is a cation exchange resin. C4H8
conversions of 97% are typical for FCC feedstocks, while higher conversions are
reached when processing steam cracker C4 cuts containing C4H8 concentrations
of approximately 25%.
MTBE is recovered as the bottoms product of the distillation unit. The methanol
containing C4 distillate is passed to the CH3OH recovery section. Water utilized to
extract excess CH3OH is recovered and recycled. The C4H8 -depleted C4 stream may
be routed to a raffinate stripper or to a molsieve-based unit for the removal of
oxygenates such as DME, CH3OH and tert-butanol.
Product Utilization: MTBE and the other tertiary alkyl ethers are primarily used in
gasoline blending as an octane enhancer to improve hydrocarbon combustion efficiency.
Methanol/water
separation
Raffinate 2
C4 feedstock
Methanol (recycle)
Methanol
MTBE product
Installations: The thyssenkrupp proprietary MTBE process has been successfully
applied in numerous refineries. The accumulated licensed capacity exceeds 1 MMtpy.
Licensor: thyssenkrupp
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com, dorothe.weimer@thyssenkrupp.com
Yields: For a C4 cut containing 22% isobutene, the C4H8 conversion can exceed 98%
at a selectivity for MTBE of 99.5%.
Utilities: C4 feed containing 22% isobutene, per metric ton of MTBE
Electricity
35 kWh
MP steam
100 kg
LP steam
900 kg
Cooling water
15 m³
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2017 REFINING PROCESSES HANDBOOK
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Ethers—Snamprogetti™
Etherification Technology (SP-Ether)
Raffinate C4
Application: The Snamprogetti Etherification Technology allows for the production
of high-octane oxygenates compounds such as methyl tert-butyl ether (MTBE), ethyl
tert-butyl ether (ETBE), tert-amyl methyl ether (TAME), tert-amyl ethyl ether (TAEE)
and etherified light cracked naphtha (ELCN).
FEED: C4 streams from the steam cracker, fluid catalytic cracking (FCC) and isobutane
dehydrogenation units, with isobutene contents ranging from 15 wt%–50 wt%, C5 and
light-cracked naphtha (LCN-FCC light gasoline 35°C–100°C) from FCCUs.
Description: A typical MTBE/ETBE unit using FCC cut is based on a single-stage
scheme, with a tubular (1) and an adiabatic (2) reactor. The front-end reactor uses
the proprietary water cooled tubular reactor (WCTR). The WCTR is a very flexible
reactor, and can treat all C4 cuts on a once-through basis. It is the optimal solution for
the etherification reaction, as it enables an optimal temperature profile with the best
compromise between kinetics and thermodynamics.
The reactors effluent is sent to the first column (3), where the product is
recovered as bottom stream, while the residual C4 are sent to the washing column (4)
to separate the alcohol. The water/alcohol stream that leaves the column is sent to an
alcohol recovery column (5) to recycle both the alcohol and the water. This scheme
will provide a total isobutene conversion of up to 95%. With the double-stage scheme,
it is possible to achieve values higher than 99%.
Industrial experience has proven the wide flexibility of this plant. The WCTR
can be easily switched from ETBE to MTBE production, and vice versa, without plant
shutdown or a reduction in feed rates. Process schemes are similar for the production
of heavier ethers, starting from C5 or LCN streams.
Advantages: High production and operative flexibility; easy startup and maintenance;
no proprietary equipment or catalyst required; high runtime.
Economics:
Utilities: (Referred to a C4 feedstock with 20 wt% of isobutylene)
Electricity
8.4 ÷ 9.2 kWh/t ether
Steam, MP and LP
0.8 ÷ 0.9 t/t ether
Water, cooling (rise 10°C)
53 ÷ 62 m³/t ether
1
2
4
3
C4 feed
5
Alcohol
Ether
Installations: More than 30 units, including MTBE, ETBE, TAME and TAEE, have been
licensed by Saipem.
Licensor: Saipem S.p.A.
Website: www.saipem.com
Contact: Maura.Brianti@saipem.com
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Ethers—TAME from refinery
and steam cracker C5 feeds
Application: The process combines skeletal isomerization and etherification steps
to maximize the production of tertiary amyl methyl ether (TAME) from refinery
and steam cracker C5 streams.
Description: TAME is formed by the catalytic etherification of reactive isoamylenes
with methanol via the CDTame® process. Skeletal isomerization increases TAME
production from an olefinic C5 stream by converting normal amylenes to isoamylenes
via the IsomPlus® process.
The combination significantly reduces olefin content while also increasing octane
value. The olefinic C5 stream is first sent to a selective hydrogenation step, where
dienes are converted to olefins. Removal of dienes reduces color, odor and gum
formation in the TAME product.
The TAME product is produced in the CDTame unit, where 95% conversion
of isoamylene is achieved. Raffinate 1 from this unit is fed to a skeletal isomerization
unit (IsomPlus), where n-pentenes are converted to isoamylenes at high yield
and selectivity. The vapor phase reaction takes place over a robust catalyst with
long cycles between regenerations.
The isomerate is then recycled to the CDTame unit where additional TAME
is produced.
Process advantages include:
• Selective hydrogenation of di-olefins at minimum capital cost
• High conversion of isoamylenes
• High conversion of normal pentenes
• High selectivity of isomerization
• Improved gasoline feedstock due to reduced color, gum formation
and olefin content
• Increased TAME production
• Increased gasoline pool octane
• Decreased gasoline pool Rvp and olefins
• Low capital and operating cost
• High-quality TAME product without objectionable odor or color.
TAME
C5 olefin
Hydrogen
Selective
hydrogenation
and CDTAME
C5 raffinate 1
Extract
Fresh methanol
Lights
ISOMPLUS
Optional
recycle
Isomerate
C5 raffinate
Recycle
Methanol
recovery
Extract
Methanol
CDTAME
Installations: With more than 35 years of experience, CB&I / Lummus Technology
has licensed more than 130 ethers units.
Licensor: Lummus Technology, a CB&I company
Contact: lummus.tech@cbi.com
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Hydrocracking—Flexible
single-stage hydrocracking
Application: Shell’s single-stage hydrocracking process covers a wide range of
conversion (from 60% to 80%) when operating in once-through mode, and up to
99% when operating in recycle mode, while processing vacuum gasoil (VGO) and
other feedstocks, such as coker gasoil, deasphalted oil and thermally cracked
gasoil, to produce ultra-low-sulfur distillates, kerosine (Jet A-1), diesel (Euro 5)
and hydrowax (unconverted oil).
The process is very flexible regarding product yield and can easily be tailored
for the production of light naphtha as a high-octane, light gasoline blending
component, and heavy naphtha as feed for the continuous catalyst regeneration
reformer for the production of gasoline and/or aromatics. The hydrowax, or
unconverted residue, has a high hydrogen (H2 ) content and is a prime feed for
secondary processing in fluidized catalytic cracking units (FCCUs), lubricant base
oil plants and ethylene crackers at lower conversions.
The high-conversion, single-stage with recycle design is applied at low
fresh-feed capacities and/or for feeds that are relatively low in nitrogen, enabling
a single reactor to be used for a cost-effective design, in many cases. For high
capacities and high-nitrogen feeds, Shell applies its two-stage hydrocracking
technology, which offers enhanced yields at a cost-effective capital cost.
Description: Heavy-feed hydrocarbons are preheated with reactor effluent (1).
Fresh H2 is combined with recycle gas from the cold high-pressure separator,
preheated with reactor effluent, and then heated in either a single- or mixed-phase
furnace, depending on design. Reactants pass via trickle flow through a multi-bed
reactor(s) containing proprietary demetalization, pretreatment, cracking and
post-treatment catalysts (2). After cooling by feed streams, reactor effluent enters
a four-separator system used in the reaction section to enhance heat integration
with the fractionation section. Hot effluent is routed to fractionation (3).
Shell’s advanced reactor internals technology, filter trays, high-dispersion (HD)
trays and ultra-flat quench (UFQ) decks, enables the application of a multi-bed
reactor design while maintaining stable operation and maximizing catalyst utilization.
Shell’s internals design achieves near 100% liquid distribution across catalyst beds,
which leads to efficient and cost-effective use of catalyst volume while minimizing
incremental pressure drop in the reactor section.
Fresh gas
Recycle gas
Process gas
Recycle
compressor
Quench gas
2
CHP
separator
Light naphtha
Heavy naphtha
3
Kerosine
HHP
separator
1
HLP
separator
Diesel
CLP
separator
Fractionator
FCC/lube
oil/ethylene
Feed
Installations: More than 50 new and revamp designs have been installed
or are under design. Revamps have been implemented in Shell and other licensors’
designs, usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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Hydrocracking—H-OilRC®
Application: H-OilRC is an ebullated-bed process for hydrocracking atmospheric or
vacuum residue. It is the ideal solution for feedstocks having high metal, CCR and
asphaltene contents. The process can operate at moderate- or high-conversion levels
while producing high-value, stable products or synthetic crude oil. Depending on the
feed and operating conditions, producing low-sulfur fuel oil (LSFO) to meet new IMO
regulations could be possible as well. H-OilRC is the heart of the H-Oil suite that offers
a very high conversion level (typically 90%) through a specific design feature of the
H-Oil reaction section, or through the combination of H-Oil with SDA or delayed coker.
Description: The flow diagram illustrates a typical H-OilRC unit that includes oil and
hydrogen (H2 )-fired heaters, an inter-stage separator, an internal recycle cup providing
feed to the ebullating pump, high-pressure separators, recycle gas purification and H2
recovery and product separation and fractionation (not required for synthetic crude oil
production). The H-Oil unit is designed with highly efficient heat integration.
Catalyst is replaced periodically in the reactor without shutdown. Different
catalysts are available as a function of the feedstock and the required objectives.
An H-Oil unit can operate for 3-yr to 4-yr run-lengths at constant catalyst activity,
with conversion in the 50%–85% range and hydrodesulfurization as high as 85%.
Typical operating conditions for H-Oil:
Temperature
Hydrogen partial pressure
LHSV, hr –1
Conversion, wt%
Arab Medium VR feed: A vacuum residue from a blend of 70% Arab Light to
30% Arab Heavy, containing 5.5 wt% sulfur, is processed at above 80% conversion
to obtain a stable fuel oil with 2 wt% sulfur.
Utilities: Per bbl of feed
Fuel
Power
Catalysts makeup
1st
stage
HP mem.
3rd
stage
2nd
stage
PSA
Fuel gas
HP abs
Inter-stage
separator
Reaction and H2
compression
section
Used catalyst
Catalyst
section
MP LT
separator
HP HT
separator
Heater
H-oil
reactors
MP abs
MP LT
separator
MP HT
separator
Resid feed
Heater
Fresh
catalyst
770°F–820°F (410°C–438°C)
1,600 psi–1,950 psi/110 bar–135 bar
0.05–0.6
50–85
Examples: Ural dominant VR feed (70% Ural + 30% Basrah)—A >540°C cut from
a Ural dominant blend is processed at 70% conversion to obtain a stable fuel oil at
1 %wt sulfur, 30% diesel and 35% VGO. The diesel cut is further hydrotreated
to meet ULSD specifications using a Prime-DTM unit.
Economics: Basis, 2016 US Gulf Coast.
Investment: $5,100–$7,400 per bpsd
Makeup H2
Atmospheric
and vacuum
fractionation
Gas
Naphtha
Diesel
VGO
VR
Fractionation section
Installations: There are 21 H-Oil units, 12 already in operation and 9 under design/
construction, with a total capacity of more than 1 MMbpsd.
References:
“Resid hydrocracker produces low-sulfur diesel from difficult feed,”
Hydrocarbon Processing, May 2006
Licensor: Axens
Website: www.axens.net/product/process-licensing/10092/h-oil-rc.html
Contact: information@axens.net
1,000 Btu
11 kWh
0.2–0.8 Lb.
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Hydrocracking—HyC-10™
Description:
Improving FCC yields, flexibility and product slate and qualities: Adding mild
hydrocracking units (MHC) upstream of the FCCU can be economically attractive
to help adapt overall FCCU performance. Such hydrotreated FCC feeds have less sulfur
and higher hydrogen-to-carbon (H/C) ratios, leading to greater product yields and
better quality of FCC gasoline, but also a reduction of FCC regenerator sulfur oxides
(SOx ) and nitrogen oxides (NOx ) emissions.
Meeting the ULSD challenge with the HyC-10 process: The relatively mild
conditions employed, i.e., moderately low H2 partial pressure (40 bar–80 bar),
do not allow the achievement of ultra-low sulfur diesel (ULSD) sulfur specifications
directly at the MHC unit outlet, requiring further hydrotreatment. Diesel out of an
MHC unit is more refractory than straight-run diesel due to higher aromatics and
organic-nitrogen content, so it requires more severe operating conditions than
most existing hydrodesulfurization units. To cope with increasing demand for ULSD,
the HyC-10 process was developed to meet that challenge while ensuring constant
MHC conversion.
In HyC-10, the H2 required for both MHC and hydrotreatment purposes is sent
to a polishing unit operated in once-through mode, before being sent to the MHC
section. Such a configuration results in equipment savings [a 35%–40% reduction
of diesel hydrotreatment inside battery limit (ISBL) cost], but also in H2 consumption
and utilities reduction.
Yields: Combining MHC and FCC adds flexibility by adjusting the balance between
gasoline and diesel production.
FCC+MHC
FCC alone
iso-VGO
iso-FCC
LPG, tons
15.1
13.5
20.0
Gasoline, tons
42.0
35.5
54.9
LCO + diesel, tons
26.8
41.7
62.9
Gasoline + LCO + diesel, tons
68.8
77.2
117.8
FCC throughput, tons
100
65
100
The first comparative example employs the same quantity of VGO feed to the
complex FCC+MHC (iso-VGO). In the second example (iso-FCC), the overall VGO feed
to the FCC+VGO complex is increased to ensure same quantity of feed to the FCCU.
Lights, naphtha
VGO
H2
Low-S VGO
Prime-D HDT
section
Diesel from CDU, FCC,
VB, coker, etc.
10 ppm S diesel
to stripping
Typical HyC-10 performance:
Feed
Conversion, %
Yields vs. feed, vol%
Naphtha
Diesel
Hydrotreated VGO
H2 consumption, wt%
Diesel properties
Sulfur, wt ppm
Cetane number
HDT-VGO (FCC feed) properties
Sulfur, ppm
Hydrogen, wt%
VGO + HCGO
20
40
1.2
5.7
20.7
36.9
80.7
61.4
1.23
1.39
< 10
< 10
48
49
< 300
13.0
< 100
13.1
Continued 
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Hydrocracking—HyC-10™ (cont.)
Advantages:
The HyC-10 unit enables diesel production with a sulfur content below 10 ppm
and improves FCCU performance:
• FCCU SOx emissions are reduced below the most stringent requirements
• Gasoline sulfur is below 10 wt% ppm
• LCO production is reduced
• LCO quality is suitable for direct blending with domestic fuel oil
( < 0.10 wt% sulfur)
• Slurry oil (< 0.29 wt% sulfur) is suitable as a low-sulfur industrial heating fuel.
In addition, HyC-10 systems can be designed to co-process other difficult
feedstocks in the refinery such as LCO, light cracked GO and visbroken GO
(HyC-10+ process).
Installations: Axens’ commercial fixed-bed VGO Hydroprocessing expertise spans
more than 110 licensed units covering all types of configurations.
Licensor: Axens
Website: www.axens.net/product/process-licensing/10088/mild-hydrocrackinga-hyc-10.html
Contact: information@axens.net
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Hydrocracking—Hydrocracking
Hydrogen makeup
Application: Haldor Topsoe’s hydrocracking process can be used to convert straight
run gas oils and heavy cracked gas oils into high-quality, sulfur-free naphtha, kerosine,
diesel and FCC feed. These products will meet the current and future regulatory
and performance requirements. In addition, high VI lube stocks and petrochemical
feedstock can be produced to increase the refinery’s profitability.
Description: Topsoe’s hydrocracking process uses well proven co-current downflow
fixed bed reactors with state-of-the-art reactor internals and catalysts. The process
uses recycled hydrogen and can be configured in partial conversion, once-through
feed mode or with recycle of unconverted oil to obtain full conversion to diesel
and lighter products. A unique heavy poly-nuclear aromatic (HPNA) Trim™ system
for HPNA management can be used to virtually eliminate unconverted oil purge.
Operating conditions: Typical operating pressure and temperature range from
55 bar–170 bar (800 psig–2500 psig) and 340°C–420°C (645°F–780°F).
Advantages: The process is highly flexible in terms of both feedstocks and products,
which allows the varying requirements of different refineries to be fully met. By
proper selection and optimization of process configuration, operating conditions and
catalysts, the Topsoe hydrocracking process can be designed for high conversion to
produce high smoke point kerosine and high cetane diesel or naphtha with a high
octane number or high aromatic potential. The process can also be designed for
lower conversion/upgrade mode to produce low-sulfur FCC feed with the optimum
hydrogen uptake or high VI (> 145) lube stock. The FCC gasoline produced from a
Topsoe hydrocracking unit does not require post-treatment for sulfur removal.
Recycle gas
compressor
Furnace
Pretreating
reactor
Hydrocracking
reactor
Process gas
H2-rich
gas
Fresh feed
Naphtha
Product
fractionator
High-pressure
separator
Middle
distillate
Low-pressure
separator
Lube stock
Development/Delivery: All elements of the process (i.e. process design,
grading, catalyst, reactor internals and technical support service program)
are proprietary to Topsoe.
Licensor: Haldor Topsoe A/S, Refinery Business Unit.
Website: www.topsoe.com/processes/hydrocracking
Contact: abj@topsoe.com
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Hydrocracking—HyK™
Application: Upgrade and convert vacuum gasoil alone or blended with various
feedstocks (light-cycle oil, deasphalted oil, ebullated bed gasoil, visbreaker
or coker gasoil).
Main product yield
Products: Diesel, jet fuel, naphtha for petrochemicals, very-low-sulfur fuel oil,
extra-quality FCC feed with limited or no FCC gasoline post-treatment,
high viscosity index lube base stocks.
Feed
Once-through
scheme
Feed
Offgas H2
Description: The hydrocracking process uses a refining catalyst and is usually
followed by hydrocracking catalyst to upgrade and convert low-value heavy
distillates into valuable products. The refining catalyst hydrotreats the feed and
removes impurities, such as nitrogen, that inhibit the cracking catalyst. Depending
on the production requirements, the cracking catalyst type and the unit’s process
scheme can be adapted to meet the desired product yields. The main features of
the hydrocracking catalyst portfolio are high tolerance towards feedstock nitrogen,
high activity to permit long cycle lengths and a wide range of selectivity towards
the desired main product (diesel, jet fuel or naphtha). Three process schemes are
available, each offering distinct advantages:
• The single-stage/once-through scheme comes with a lower investment cost
and offers the possibility to valorize the unconverted oil as top-quality Group III
lube base or as a petrochemicals feedstock.
• The single-stage/once-through with recycle scheme boosts conversion and
selectivity towards valuable fuels with a moderate increase of the investment cost.
• The two-stage scheme offers the best selectivity towards high-value middle
distillates or naphtha for petrochemicals, while minimizing the unconverted bleed.
Installations: More than 100 references with a cumulative capacity exceeding 4.2
MMbpsd and conversions exceeding 99%. High flexibility regarding feedstock quality,
ranging from typical straight-run VGO to deasphalted oil, heavy coker gasoil, extra
heavy crude oil VGO and ebullated bed effluents.
Two-stage scheme
Feed
Once-through
with recycle scheme
H2
Reaction
section
Naphtha
Offgas
Reaction
section
1st stage
Naphtha
Kerosine
Diesel
Naphtha
Kerosine
Diesel
Kerosine
H2
Offgas
2nd stage
LCO bleed
Clean fuels
Petchem feed
Diesel
Recycle
UCO bleed
Gr III lubes
References:
1. Morel, F., J. Bonnardot and E. Benazzi, “Hydrocracking solutions squeeze more
ULSD from heavy ends: New processing alternatives enable upgrading vacuum
residuals into higher-value products,” Hydrocarbon Processing, November 2009.
Licensor: Axens
Website: www.axens.net/product/technology-licensing/10052/hyk
Contact: www.axens.net/contact.html
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Hydrocracking—ISOCRACKING®
Application: The process offers flexibility to process opportunity crudes in a
refinery while producing premium-grade clean transport fuels that meet stringent
specifications. Chevron Lummus Global’s (CLG’s) ISOCRACKING process can convert
naphthas, AGO, VGO, DAO, cracked oils from FCCUs, delayed cokers and visbreakers,
intermediate products from residue hydroprocessing units, synthetic gasoils and shale
oil. Unit capacities can range from 9 Mbpsd–140 Mbpsd.
Products: Lighter, high-quality, more valuable products: LPG, gasoline, catalytic
reformer feed, jet fuel, kerosine, diesel and feeds for FCC, ethylene cracker or lube oil
units. Based on demand, the unit can be designed to maximize CCR feed or middistillates. With an appropriate catalyst system, the flexibility to swing the products in
favor of CCR feed or mid-distillates can be achieved. Using CLG’s patented scheme,
HCR can be designed to process cracked and SR feedstock blend while producing
UCO with 140+ VI to produce Group-III+ LBO.
Description: A broad-range catalyst, amorphous, zeolitic, supported/unsupported
and noble-metal zeolitic are used to tailor the ISOCRACKING process to a refiner’s
objectives. CLG offers multiple schemes, such as single-stage once through (SSOT),
two-stage recycle (TSRE), optimized partial conversion (OPC), single-stage recycle
(SSRE), single-stage reaction sequenced (SSRS) and split feed (for widely different
reactive feed). The appropriate scheme is selected based on unit capacity and objective.
An SSOT scheme is typically used for mild hydrocracking, or when a significant
quantity of unconverted oil is required for FCC, lubes or ethylene units. An SSRE
option is used for lower capacity units, when economical. For feeds that are high in
nitrogen and other contaminants, CLG recommends the OPC scheme, which achieves
gravity targets of unconverted oil (typical FCC feed) and desired conversion at much
lower CAPEX and hydrogen (H2) consumption. The reactors use a patented internals
technology called ISOMIX-e® for mixing and redistribution.
Most modern large-capacity flow schemes processing heavy sour feed require
two reactor stages (1, 4), and one high-pressure separation system (2), with an
optional recycle-gas scrubber (5) and one recycle-gas compressor (8). The lowpressure separators (3), product stripper (6) and fractionator (7) provide the flexibility
to fractionate products either between reaction stages or at the tail-end, depending
on desired product slate and selectivity requirements.
Operating conditions: Typical for an HCR:
H2 partial pressure
LHSV, 1/hr
100 bar–145 bar
0.4–1.5
First-stage (or once-through reactor) temperature
Second-stage (No H2S and NH3 inhibition) temperature
Yields:
Feed/objective
Max. mid-distillates
(Jet + diesel), vol%
Heavy naphtha in max.
naphtha mode, vol%
UCO to lubes*, vol%
UCO to cracker, vol%
380°C–427°C
304°C–388°C
VGO blend (including
cracked feedstock like
HCGO, resid HCR VGO)
75%–95%
Diesel blend (including
cracked feedstock like
LCGO, resid HCR Diesel)
75%–85%
65%–80%
5%–40% (with > 140 VI)
40%–60% with 6–8 BMCI
* Lube operation will require limiting the amount of cracked feedstock in the feed blend
The unit can be designed to switch operation between max. naphtha and max.
mid-distillates.
Continued 
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Hydrocracking—ISOCRACKING® (cont.)
Advantages: Best-in-class in energy consumption—units have been rated in the
top 25% of the Solomon Index. Most of the high-capacity units (> 50 Mbpsd) such
as SATORP, YASREF, etc., and high-severity units (> 95% conversion) have been
designed by CLG since 2000. The company has a wealth of database and experience
in processing feedstock containing high percentage of HCGO (> 65%) and residue
hydrocracker VGO. Many units have been designed and are operating in flexible mode,
max. naphtha and max. mid-distillate mode to remain competitive in varying markets.
Installations: Since 2000, CLG has licensed more than 70 hydrocracking units
and more than 300 total licenses, including all technologies. CLG has licensed
and successfully started up many units that were first-of-a-kind globally, such as
the high-conversion hydrocracker in Neste, Finland that is processing residue
hydrocracker VGO; a unit processing 65+% HCGO in the feed for Valero, Port Arthur,
Texas; and most of the large high-conversion hydrocracking units such as SATORP
(120 Mbpsd), YASREF (124 Mbpsd) and many others.
Economics:
Investment: Investment can vary, depending upon the severity, capacity and
location of the unit, but typical US Gulf Coast (USGC), 2017 basis installed costs are in
the range of $5,000/bbl–$8,000/bbl.
Utilities: Utilities can vary depending on the hydrocracker’s configuration
and operating severity. However, a typical two-stage full conversion hydrocracker
with a capacity of 60 Mbpsd would have following utility consumption:
Electricity, kWh
22,500
Steam (export at 38 bars), Kg/hr
3,500
C.W. rise (6°C), gpm
950
Fuel (absorbed), MM Kcal/hr
61
Licensor: Chevron Lummus Global LLC
Development/Delivery: Chevron Research Co. invented modern hydrocracking in
1959–1960 to convert Californian gasoils to jet fuel and aphtha. The process was called
ISOCRACKING because lighter products had an unusually high iso-paraffin-to-normal
paraffin ratio. Chevron was in a unique position of being an owner, operator and
licensor of hydrocrackers. In 1993, Chevron and Lummus Global formed an alliance
to jointly research and develop hydrocracking and to jointly license hydrocracking
technology. Lummus was one of the world’s leading licensors of both petrochemicals
and refining technologies, and with the formation of the marketing alliance and
global footprint, Chevron and Lummus Global won more the 50% of the market share
in hydrocracking licenses. In 2000, the alliance was converted to a true 50:50 joint
venture and Chevron Lummus Global (CLG) was formed. The technology portfolio
was expanded to include LC-FINING, LC-MAX, RDS, Lube Base Oil Dewaxing/
Hydrofinishing and ISOTREATING. In 2015, the LC-SLURRY, delayed coking and
SDA were added to the CLG portfolio.
Website: www.chevronlummus.com
Contact: Arun.Arora@cbi.com
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Hydrocracking—LC-MAX
VR-fining reactor 1st stage
65-70% conversion
Application: High-conversion hydrocracking of vacuum residue, utilizing two reliable,
commercially proven LC-FINING and solvent deasphalting (SDA) platforms.
Description: Fresh vacuum or atmospheric residue feed is mixed with hydrogen (H2 )
and reacted in a 1st-stage VR ebullated bed reactor at moderate-to-low temperatures
within an expanded catalyst bed. Catalyst bed expansion is maintained by means of
internal liquid circulation targeting isothermal operation. After product fractionation,
naphtha, diesel and VGO products are recovered. Bottom of the vacuum tower—
unconverted oil (UCO)—is routed to an SDA operating at high lift. DAO product is further
converted in a 2nd-stage DAO ebullated bed reactor. Product stability is improved by
adjusting 1st- and 2nd-stage operating conditions, allowing mitigation of downstream
equipment fouling. A commercially proven dual-type catalyst system is utilized to
favor desired reactions. Catalyst is added and withdrawn, typically on a daily basis. The
majority of H2 is recovered in membrane or PSA systems, which are fully integrated into
the LC-MAX process. The overall conversion that is safely achievable exceeds 92 wt%.
Pitch from SDA can be pelletized, stored and burnt at power plants or cement plants.
Operating conditions:
Reactor temperatures, °F
Reactor pressure, psig
H2 partial pressure, psig
LHSV
Conversion, %
Desulfurization, %
Demetalization, %
CCR reduction, %
730–840
1,650–3,500
1,100–2,500
0.1–0.5
> 90
60–90
60–95
45–78
Yields: For Arabian Light/Arabian Heavy blend:
Feed
Gravity, API
3.51
Sulfur, wt%
5.1
Ni+V, ppmw
220
Conversion, %
92
DAO LC-fining reactor 2nd stage
80-90% conversion
Catalyst B
Catalyst A
Products, vol%
C4, %
C5 – 302°F, %
302°F–700°F
700°F–1,004°F
1,004°F+
SDA
3.5
15.1
52.9
31.0
8.0
Advantages: Minimized downstream equipment fouling, commercially proven,
diesel selective process, VGO suitable for RFCC. Possible integration with hydrotreater
or hydrocracker to produce Euro 5 diesel.
Continued 
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Hydrocracking—LC-MAX (cont.)
Economics:
Investment, estimated (US Gulf Coast, 1Q/2017)
Size, bpsd fresh VR feed
50,000
$/bpsd typical fresh feed
10,360
Utilities: Typical per 50,000 bpd
Electricity, kW
HP Steam, kg/h
Cooling water, m3/h
Fuel consumption, MW
29,800
8,400
5,100
47.3
Installations: Nine large commercial LC-FINING units are in operation; one LC-FINING
unit is under construction; five LC-FINING or LC-MAX units are in various phases
of front-end engineering; and three LC-FINING, LC-SLURRY and LC-MAX units
are in design phase.
Licensor: Chevron Lummus Global LLC
Website: www.chevronlummus.com
Contact: rhurny@cbi.com
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Hydrocracking—Maximum (heavy)
naphtha hydrocracking
Fresh gas
Application: Shell’s maximum naphtha hydrocracking process is a single-stage,
hydrocracking process with recycle for the full conversion (up to 99%) of vacuum
gasoils (VGOs) or distillates (kerosine and/or diesel). The process enables maximum
production of naphtha as either continuous catalyst regeneration reformer feed for
gasoline and aromatics production, or as feed for the ethylene cracker.
Description: The hydrocarbons feed are preheated with reactor effluent (1).
Fresh hydrogen (H2) is combined with recycle gas from the cold high-pressure
separator, preheated with reactor effluent, and then heated in a single-phase furnace.
Reactants pass via trickle flow through a multi-bed reactor(s) containing proprietary
pretreatment, cracking and post-treatment catalysts (2). Interbed ultra-flat quench
(UFQ) internals and high-dispersion (HD) nozzle trays combine excellent quench,
mixing and liquid flow distribution at the top of each catalyst bed, while maximizing
reactor volume utilization. After cooling by feed streams, reactor effluent enters
a separator system. Hot effluent is routed to fractionation (3).
Shell’s advanced reactor internals technology, HD trays and UFQ decks,
enables the application of a multi-bed reactor design while maintaining stable
operations and maximizing catalyst utilization. A four-separator system is used
in the reaction section to enhance heat integration with the fractionation section.
Recycle gas
Process gas
Recycle
compressor
Quench gas
2
CHP
separator
Light naphtha
Heavy naphtha
3
Kerosine
HHP
separator
1
Feed
HLP
separator
Diesel
CLP
separator
Fractionator
FCC/lube
oil/ethylene
Installations: More than 50 new and revamp designs have been installed or
are under design. Revamps have been implemented in Shell and other licensors’
designs, usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrocracking—Mild hydrocracking
Fresh gas
Application: Shell’s mild hydrocracking (MHC) process is a single-stage, oncethrough process for the partial conversion of vacuum gasoil (VGO) and other
feedstocks, such as coker gasoils, deasphalted oils and thermally cracked gasoils,
into ultra-low-sulfur distillates, kerosine, diesel, and hydrowax (unconverted oil). Shell
MHC produces a hydrowax with lower aromatics and sulfur, and higher hydrogen
(H2 ) content when compared with normal vacuum gasoil hydrotreating, thereby
adding substantial value as feedstock for fluidized catalytic cracking (FCC), ethylene
cracking or base oil integration. Typical properties for MHC distillates depend on the
conversion level applied (normally 30%–60%) and on the MHC feed quality. Distillate
properties—sulfur levels below 10 ppm, density and cetane index meeting Euro 5
diesel specifications—can be achieved. Post-treating of the MHC diesel in a lowpressure hydrotreating process can be used for certain applications.
Description: The general equipment requirements for MHC are the same as
for many existing VGO hydrodesulfurization (HDS) units. The primary difference
is the need for increased reactor volume to provide sufficient catalyst to achieve
the desired conversion and cycle life. Shell’s advanced reactor internals design
achieves near 100% liquid distribution across catalyst beds, which leads to the
efficient and cost-effective use of catalyst volume while minimizing incremental
pressure drop in the reactor section.
Shell’s advanced reactor internals technology, high-dispersion (HD) trays
and ultra-flat quench (UFQ) decks, enable the application of a multi-bed reactor
design, while maintaining stable operation and maximizing catalyst utilization.
A four-separator system is used in the reaction section to enhance heat integration
with the fractionation section.
High-activity hydrodenitrogenation (HDN) and HDS catalysts are available from
Shell’s affiliate Criterion Catalysts & Technologies Inc. (Criterion) for MHC. Criterion
offers three different catalyst systems for MHC, as well as service that depends
on the required conversion. All-alumina catalysts are used for low-conversion,
a combination of alumina (HDS/HDN) and silica alumina (hydrocracking) catalysts
for low- to moderate-conversion, and a combination of alumina (HDS/HDN) and
zeolite (hydrocracking) catalysts for higher conversion. MHC is typically designed
to operate at a lower pressure than full conversion hydrocracking and utilize
a once-through configuration, which significantly reduces capital investment
and results in lower operating costs with substantially less H2 consumption.
Recycle gas
Process gas
Recycle
compressor
Quench gas
2
CHP
separator
Light naphtha
Heavy naphtha
3
Kerosine
HHP
separator
1
HLP
separator
Diesel
CLP
separator
Feed
Fractionator
FCC/lube
oil/ethylene
Processing alternative feedstocks: Many refiners are adding residue schemes
to reduce or eliminate the production of high-sulfur fuel oil. The most often-applied
solutions are delayed coking, solvent deasphalting and thermal conversion.
Shell’s MHC process can economically upgrade the intermediate products from
these processes (coker gasoils, deasphalted oils and thermally cracked gasoils) to
low-sulfur, high-cetane diesel and kerosine. The middle distillates are all very low
in sulfur and have a quality comparable to that produced by VGO-only processing.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrocracking—Residue VCC™
Application: The Veba Combi Cracker (VCC) technology is a slurry-phase
hydrocracking/hydrogenation process for converting petroleum residues at very-high
conversion rates (greater than 95% and over 524°C) and liquid yields (above 100 vol%)
directly into marketable products.
The process applies the principles of the Bergius-Pier process for primary
conversion of heavy residual oils or coal into light distillates.
Description: The slurry is mixed with hydrogen (H2 ) (recycle and makeup) and
brought to the reactor inlet temperature conditions. The operating conditions (pressure,
temperature, space velocity and additive concentration) are adjusted to accomplish
a greater than 95% conversion of the residuum in a once-through mode of operation.
The slurry phase reactor has no internals and is operated in an up-flow mode.
The unconverted residual oil and the additive are separated from the vaporized
reaction products and the recycle gas in a hot separator. The hot separator bottom
product is fed into a vacuum flasher for additional distillate recovery. The recovered
distillates are routed to a directly coupled hydrotreating stage with the hot-separator
overhead products.
The hydrotreating stage is typically a catalytic fixed-bed reactor operated under
essentially the same pressure as the primary conversion stage. This second stage may
be designed for either hydrotreating or hydrocracking applications.
Additional low-value refinery streams such as gasoils, deasphalted oils or fluid
catalytic cracking (FCC) cycle oils may also be directly added to the second stage.
Products from the second stage are cooled and, depending on the owner’s needs, the
recovered liquids may be stripped for synthetic crude oil production or fractionated to
produce finished saleable products.
The vapor stream is typically stripped of its impurities, and the resultant H2 -rich
gas stream is recycled to the slurry reactor to maintain the desired treat rate and
H2 partial pressure.
The unit operates essentially in a once-thru mode, and the asphaltenes
conversion is typically greater than 90%. This differentiates this technology from
competing processes. KBR’s additive composition and structure provide for reliable
entrapment and removal of the unconverted high metals containing residual material,
essentially eliminating fouling tendencies.
Advantages: Since the VCC adopts a once-through, slurry-phase reactor system,
the unit is capable of operating at 65,000 bpd or higher, using a single-reactor-train
system. When compared to ebullated-bed technologies, the diameter and weight
of the reactor are substantially lower.
1st. stg.
Hot
reactor separator
Vacuum residue
2nd. stg.
reactor
Cold
separator
Recycle
gas
compressor
Offgases,
sulfur, etc.
Gas
cleaning
Offgases
H2
Heater
T
Makeup
compressor
Naphtha
Vacuum
column
Middle
distillate
Fractionator
Residue
Vacuum
gasoil
Economics: Based upon a comparative study for an actual refinery, KBR estimates
that the net present value and the internal rate of return for the VCC process
will outperform delayed cokers when benchmark crude prices exceed $45/bbl.
For a VCC residue upgrading refinery unit, the ISBL cost on the US Gulf Coast (2016)
basis is estimated at approximately $10,000/bpd–$13,000/bpd for coal and
petroleum feedstocks.
Installations: Dozens of VCC units have been built.
References:
1. Motaghi, M. and A. Subramanian, “Slurry-phase hydrocracking—possible solution
to refining margins,” Hydrocarbon Processing, February 2011.
Licensor: KBR and BP
Contact: technologyconsulting@kbr.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrocracking—Two-stage, maximum
diesel hydrocracking
Application: Shell’s two-stage hydrocracking process is for the full conversion
(up to 99%) of vacuum gasoil and other feedstocks, such as coker and thermally
cracked gasoils. The two-stage design is selected for high fresh-feed capacities and/
or feeds that are relatively high in nitrogen, thereby offering high middle distillate
yields. The design is flexible and capable of producing maximum ultra-low-sulfur
distillates, kerosine (Jet A-1) and diesel (Euro 5). The design can also be tailored for
the production of light naphtha as a high-octane light gasoline blending component,
and heavy naphtha as feed for the continuous catalyst regeneration reformer for the
production of gasoline and/or aromatics. The hydrowax, or unconverted oil, yield–
is small–but has a high hydrogen (H2 ) content and is a prime feed for secondary
processing in fluidized catalytic cracking units (FCCUs), lubricant base oil plants and
ethylene crackers.
Description: Heavy-feed hydrocarbons are preheated with first-stage reactor
effluent (1). Fresh H2 is combined with recycle gas from the cold high-pressure
separator, preheated with combined reactor effluent, and then heated in a singleor mixed-phase, first-stage furnace, depending on design. Reactants pass
via trickle flow through a multi-bed reactor(s) containing proprietary
demetalization, pretreatment, cracking and post-treatment catalysts (2).
Shell’s advanced reactor internals technology, high-dispersion (HD) nozzle
trays and interbed ultra-flat quench (UFQ) decks, combine excellent quench,
mixing and liquid flow distribution at the top of each catalyst bed, while maximizing
reactor volume utilization.
After cooling by the fresh-feed stream, the first-stage reactor effluent is mixed
with second-stage reactor effluent and then enters a separator system. Hot effluent
is routed to fractionation (3). A hydrocarbon stream is recycled from the bottom of
the fractionator and routed to the second stage where it is preheated with secondstage reactor effluent mixed with hot recycle gas and passed via trickle flow through
a multi-bed reactor containing proprietary cracking catalysts. The second-stage
reactor effluent is cooled by second-stage feed, and is then mixed with first-stage
effluent and routed to a separator system. Shell HD trays and UFQ decks enable
the application of a multi-bed reactor design, while maintaining stable operation
and maximizing catalyst utilization. A four-separator system is used in the reaction
section to enhance heat integration with the fractionation section.
Fresh hydrogen from B/L
K-1701
F-1701
HGO/VGO
from B/L
R-1701
Note 2
K-1702
RFG
SC
High pressure
amine system
DAO
from B/L
V-1702
Fresh wash
water from B/L
F-1702
Unconverted
oil from
fractionation
section
V-1704
Note 3
RFG
R-1702
Note 2
Note 1
Offgas to LP
amine absorber
V-1705
Heavy liquid feed
to fractionation
section
Sour water
to B/L
Light liquid feed to
fractionation section
Installations: More than 50 new and revamp designs have been installed or
are under design. Revamps have been implemented by Shell and other licensors’
designs, usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—Haldor Topsoe
Convective Reformer (HTCR)
S-removal
Application: Produce hydrogen (H2 ) from a hydrocarbon feedstock, such as natural
gas, LPG, naphtha or refinery offgases, using the Haldor Topsoe Convective
Reformer (HTCR). Plant capacities range from 5 MNm3/h to more than 50 MNm3/h (5
MMscfd to more than 45 MMscfd), and hydrogen purities from 99.5% to 99.999+% are
marketed. This can be achieved without any steam export.
Description: The HTCR-based H2 plant can be tailored to suit customer needs
with respect to feedstock flexibility. Typical plants include feedstock desulfurization,
pre-reforming, HTCR reforming, shift conversion and PSA purification to obtain
product-grade hydrogen. PSA offgas is used as fuel in the HTCR. Excess heat
in the plant is efficiently used for process heating and steam generation.
A unique feature of the HTCR is the high thermal efficiency. Product and
flue gas are both cooled by providing heat to the reforming reaction. The high thermal
efficiency allows for the design of energy-efficient H2 plants without steam export.
ln the larger plants, the reforming section consists of two HTCR reformers.
Prereformer
HTCR
PSA
Shift
Steam
H2
3x
Feed
Combustion air
Flue gas
Offgas
Fuel
Economics: HTCR-based H2 plants provide low investment and low operating
costs for H2 production. The plant can be supplied skid-mounted, providing a short
erection time. The plants have high flexibility, reliability and safety. Fully-automated
operation, startup and shutdown allow minimum operator attendance. Feed and
fuel consumption of about 3.3 Gcal/1,000 Nm3–3.4 Gcal/1,000 Nm3 (350 Btu/scf–
360 Btu/scf) is achieved, depending on layout and feedstock.
Installations: 40 licensed units with capacities of up to 30 MNm³/h (27 MMscfd).
Licensor: Haldor Topsoe A/S
Website: www.topsoe.com/processes/hydrogen
Contact: tlys@topsoe.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—
Heat Exchange Reforming (HTER)
Application: The Haldor Topsoe Exchange Reformer (HTER) is a gas-heated
convection reformer operating in parallel with the tubular reformer. Process gas
from the tubular reformer outlet is used as a heating medium. The main advantage
of the HTER unit is the significant savings on fuel gas to the tubular reformer.
The HTER can also be used in the revamp of existing plants, offering a hydrogen (H2 )
production capacity increase of up to 30% without requiring modifications to the
existing tubular reformer.
Description: The HTER reformer is placed in parallel with a traditional tubular
reformer. The HTER unit consists of a cylindrical, refractory-lined pressure vessel
with a number of concentric, high-alloy double tubes arranged in a circular pitch.
Reforming catalyst is loaded into the innermost tubes and outside of the outer tubes.
Part of the feed gas is split before reaching the tubular reformer and sent to the HTER
unit. The feed gas flows downward through the catalyst beds. At the bottom of the
reactor, the reformed gas is mixed with hot effluent from the tubular reformer.
The combined tubular reformer/HTER effluent gas then flows upward through the
annuli of the double tubes and is cooled by the gas flowing downward in the catalyst
bed, thus providing the necessary heat for the endothermic reforming reactions.
Prereformer
Tubular reformer
HTER-p
Process steam
Desulfurized feed
To CO shift
converter
To stack
Fuel
Economics: The advantages of using HTER technology are lower fuel consumption,
reduced steam export and lower CO2 emissions. lt also provides an economically
attractive and smaller-plot-area solution for the capacity increase of existing H2
plants. The combined steam methane reformer (SMR) and HTER plant can achieve
feed and fuel consumption of about 3.4 Gcal/1,000 Nm³–3.5 Gcal/1,000 Nm³
(361 Btu/scf–372 Btu/scf) and net energy consumption of about 3.15 Gcal/1,000 Nm³–
3.30 Gcal/1,000 Nm³ (335 Btu/scf–351 Btu/scf), depending on layout and feedstock.
References:
1. Olsson, H., P. Rudbeck and K. H. Andersen, “Adding H2 Production Capacity
by Heat Exchange Reforming,” XIV Refinery Technology Meet (RTM)
on Energy & Environment, India, September 2007.
Installations: Two licensed units in operation for expansions at existing plants,
with capacity increases of up to 30 MNm³/h (27 MMscfd). Six licensed units under
engineering and/or construction for expansions at existing plants with capacity
increases of up to 30 MNm³/h (27 MMscfd). One licensed unit in operation
for a grassroots H2 plant with a capacity of 25 MNm³/h (22 MMscfd) [total plant
H2 capacity is 130 MNm³/h (116 MMscfd)]. Six licensed units under engineering
and/or construction for grassroots H2 plants with capacities up to 30 MNm³/h
(27 MMscfd) [total plant H2 capacities up to 200 MNm³/h+ (180+ MMscfd)].
Contact: tlys@topsoe.com
Licensor: Haldor Topsoe A/S
Website: www.topsoe.com/processes/hydrogen
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2017 REFINING PROCESSES HANDBOOK
COMPANY INDEX
Hydrogen Generation—Hydrogen
by Steam Reforming
Application: Production of hydrogen H2 from hydrocarbon (HC) feedstocks, by
steam reforming.
Feedstocks: Ranging from natural gas to heavy naphtha as well as potential refinery
offgases. Many recent refinery hydrogen plants have multiple-feedstock flexibility,
either in terms of backup or alternative or mixed feed. Automatic feedstock change
over has also successfully been applied by TechnipFMC in several modern plants
with multiple-feedstock flexibility.
Description: The generic flowsheet consists of feed pretreatment, pre-reforming
(optional), steam-HC reforming, shift conversion and H2 purification by pressure
swing adsorption (PSA). However, it is often tailored to satisfy specific requirements.
Feed pretreatment normally involves removal of sulfur, chlorine and other
catalyst poisons after preheating to an appropriate level.
The treated feed gas mixed with process steam is reformed in a fired reformer
(with adiadatic pre-reformer upstream, if used) after necessary superheating.
The net reforming reactions are strongly endothermic. Heat is supplied by
combusting PSA purge gas, supplemented by makeup fuel in multiple burners in
a top-fired furnace.
Reforming severity is optimized for each specific case. Waste heat from
reformed gas is recovered through steam generation before the water-gas shift
conversion. Most of the CO is further converted to H2 in the shift reactor. Process
condensate resulting from heat recovery and cooling is separated and generally
reused in the steam system after necessary treatment. The entire steam generation
is usually on natural circulation, which adds to higher reliability. The gas flows to
the PSA unit, which provides high-purity H2 product (up to < 1 ppm CO) at nearinlet pressures.
Typical specific energy consumption based on feed + fuel – export steam ranges
between 3.0 Gcal/KNm3 and 3.5 Gcal/kNm3 of H2 (330 Btu/scf–370 Btu/scf) on a
lower heating valve basis depending upon feedstock, plant capacity, optimization
criteria and steam-export requirements.
Recent advances include integration of H2 recovery and generation, and
recuperative reforming in a TechnipFMC Parallel Reformer (TPR®), which is especially
suitable for capacity retrofits.
Recycle H2
Process steam
Feedstock
Feed
pretreatment
Steam
system
Prereformer
(optional)
PSA purge gas and makeup fuel
Export steam
Vent steam
Reformer
Air
preheater
PROCESS CATEGORIES
Steam
sys.
Steam
system
Process
coils
BFW preparation
Shift
conv.
Air
Process
condensate
Cooling
train
Feed or
steam
Demineralized
water
Dosing
Purge gas
fuel to
reformer
PSA
unit
H2 prod.
Recycle H2
Installations: TechnipFMC’s H2 plant technology has been applied in more than 270
plants worldwide covering a wide range of capacities from 500 Nm3/h–250,000
Nm3/h. Most installations are for refinery application with basic features for high
reliability and optimized cost. For 20 years TechnipFMC has designed and supplied
hydrogen plants for Air Products under the Hydrogen Alliance for “over the fence”
hydrogen supply (www.h2alliance.com). Air Products is one of the world’s largest
producers of outsourced hydrogen, with more than 80 plants and 700 miles of
pipeline. TechnipFMC is the market leader in design and supply of hydrogen plants,
worldwide.
Licensor: TechnipFMC
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—
Pre-reforming with feed
ultrapurification
Application: Ultra-desulfurization and adiabatic steam reforming of hydrocarbon
feed ranging from refinery offgas or natural gas to LPG and naphtha feeds as
a pre-reforming step in the route to hydrogen (H2 ) production.
Description: Organic sulfur components contained in the hydrocarbon feed are
converted to hydrogen sulfide (H2 S) in the hydro-desulfurization vessel and, with any
H2 S already present, are then fed to two desulfurization vessels in series. Each vessel
contains two catalyst types: the upper layer for bulk sulfur removal, and the bottom layer
for ultrapurification down to sulfur levels of less than 10 ppb or lower.
The two desulfurization vessels are arranged in series so that either may
be located in the lead position, allowing online catalyst change-out. The novel
interchanger between the two vessels allows for the lead and lag vessels to work
under different optimized conditions for the duties that require two catalyst types.
This arrangement may be retrofitted to existing units.
Desulfurized feed is then fed to a fixed bed of nickel-based catalyst that converts
the hydrocarbon feed, in the presence of steam, to a product stream containing
methane (CH4 ), H2 , carbon monoxide (CO), carbon dioxide (CO2 ) and unreacted
steam, which is suitable for further processing in a conventional fired reformer.
The pre-reformer containing CRG catalyst decreases capital costs in the fired
reformer due to reductions in the radiant box heat load. It also allows high-activity,
gas-reforming catalyst to be used. The ability to increase preheat temperatures
and transfer radiant duty to the convection section of the fired reformer can
minimize involuntary steam production.
Operating conditions: The desulfurization section typically operates between
300°C–400°C, and the CRG pre-reformer will operate over a wide range of
temperatures from 450°C–650°C and at pressures up to 75 bara.
Yields: Regardless of feed type, CRG catalyst will convert all of the reactants to
a product gas composition that is established at steam-methane and water gas
shift equilibrium at the prevailing bed exit temperature. This provides a stable,
well-conditioned feed for the fired reformer.
Advantages: For a new plant build, deployment of a pre-reformer generates capital
savings through a reduction in the size of the fired reformer. For revamps, the
Steam
Preheat
Preheat
Product gas
HDS vessel
Lead
desulfurization
vessel
Lag
desulfurization
vessel
CRG
prereformer
Hydrocarbon feed
main benefit is that plant production can be increased by typically 10% or, at fixed
production rates, the plant thermal efficiency can be enhanced through reduced fuel
usage, as well as the associated benefits of longer fired reformer tube and catalyst life.
Investment: Numerous local plant factors must be considered when deciding whether
to install a pre-reformer—value of steam, range of feedstocks and their cost, flowsheet
steam-carbon ratio, etc.—and so each case must be treated on its own merits.
Development/Delivery: The CRG catalyst is manufactured under license
by Johnson Matthey.
Installations: CRG catalyst covers more than 50 yr of experience, with more than 150
plants built and operated. The ongoing development of both technologies has been
implemented into 40 H2 plants in the last 10 yr.
References:
1. Broadhurst, P., “The application and economics of pre-reforming technology in
uprating existing hydrogen production assets,” LARTC Annual Meeting, Miami,
Florida, June 2015.
Continued 
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COMPANY INDEX
Hydrogen Generation—Pre-reforming with feed ultrapurification (cont.)
2. Cross, J., G. Jones and M. A. Kent, “An introduction to pre-reforming catalysts,”
Nitrogen & Syngas 341, May–June 2016.
Licensor: The DAVY process and CRG catalyst are licensed by Johnson Matthey.
DAVY is a registered trademark of the Johnson Matthey group of companies.
Website: www.matthey.com
Contact: licensing@matthey.com
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydrogen Generation—
PRISM® Membranes
Application: To recover and purify hydrogen (H2 ) or to reject H2 from refinery,
petrochemical or gas processing streams using a PRISM Membrane. Refinery
streams include hydrotreating or hydrocracking purge, catalytic reformer off-gas,
fluid catalytic cracker off-gas or fuel gas. Petrochemical process streams include
ammonia synthesis purge, methanol synthesis purge or ethylene off-gas. Synthesis
gas includes those generated from steam reforming or partial oxidation.
Description: Typical PRISM Membrane systems consist of a pretreatment section
(1) to remove entrained liquids and preheat feed before gas enters the membrane
separators (2). Various membrane separator configurations are possible to optimize
purity, recovery, and operating and capital costs, such as adding a second-stage
membrane separator (3). Pretreatment options include water scrubbing to recover
ammonia from an ammonia synthesis purge stream.
Membrane separators are compact bundles of hollow fibers contained in a
coded pressure vessel. The pressurized feed enters the vessel and flows on the
outside of the fibers (shell-side). H2 selectively permeates through the membrane
to the inside of the hollow fibers (tube-side), which is at lower pressure. PRISM
Membrane separators’ key benefits include resistance to water exposure,
particulates and low feed to non-permeate pressure drop.
Operating conditions: PRISM Membrane systems operate at pressures close
to plant processes, so no additional compression is required, typically between
70 barg–90 barg.
Advantages: PRISM Membranes are passive units that can tolerate fluctuations
in flowrates and purities. Separators operate in parallel, making capacity turndown
as easy as closing a valve. PRISM Membranes will allow for production fluctuations
that will disable alternative technologies.
Economics: Return on investment is between 6 mos (ammonia synthesis) and
24 mos (hydroprocessing units), depending on production volumes.
Investment: Economic benefits are derived from high-product recoveries and
purities, high reliability and low capital cost. Additional benefits include relative
ease of operation with minimal maintenance. Also, systems are expandable and
adaptable to changing requirements.
Development/Delivery: Membrane systems consist of a pre-assembled skid unit with
pressure vessels, interconnecting piping and instrumentation, and are factory tested
for ease of installation and commissioning. Air Products’ engineering team will work to
design an optimized system for each project’s flow requirements.
Installations: More than 500 PRISM Membrane systems have been commissioned.
These systems include more than 85 systems in refinery applications, 210 in ammonia
synthesis purge and 60 in synthesis gas applications.
Licensor: Air Products and Chemicals Inc.
Website: www.airproducts.com/products/Gases/supply-options/prism-membranes/
prism-membrane-engineered-systems.aspx
Contact: membrane@airproducts.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydrogen Generation—
PSA Purification
Production
Application
Recovery and purification of pure hydrogen from different H2-rich streams.
Feedstock is raw hydrogen from steam methane reforming (SMR), partial
oxidation, cryogenic purification, methanol plant purge gases, ethylene offgas,
styrene offgas, gasification, ammonia plant, CCR, and other offgases;
or any combination of the above.
Product is H2 of up to 99.9999% purity, with no coproducts.
Description
Units are available in 5,000 Nm3/hr–200,000 Nm3/hr capacities.
Pure H2 product is delivered at a pressure close to feed pressure (pressure drop
across PSA could be as low as 0.5 bar), and impurities are removed at a lower pressure
(typical PSA offgas pressures range from 1.1 bara–10 bara).
The PSA tail gas, containing impurities, can be sent back to the fuel system (SMR
burners or refinery fuel network) with or without the need of a tail gas compressor.
Operation is fully automatic.
Feed
Offgas
drum
Offgas
Advantages
PSA units use the most advanced adsorbents on the market and patented highefficiency cycles to provide maximum recovery and productivity. Typical on-stream
factors are > 99.9%. Turndown can be as low as 25%.
PSA units are compact, fully skid-mounted, pretested units designed for outdoor
and unattended operation.
Economics
H2 recovery rate: 60% to 90%.
OPEX: Feed + fuel ~13.6 MJ/Nm3 H2 (figures based on natural gas)
CAPEX: $1 MM–$3 MM
Licensor
Air Liquide Engineering & Construction
References
70 units in operation or under construction.
Website
www.engineering-airliquide.com/hydrogen
Contact
hydrogen@airliquide.com
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PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—
SMR Production
Flue gas
Application
Generation of syngas through catalytic conversion of methane rich hydrocarbon
feedstocks in the presence of steam in a top fired steam reformer. Feedstock is natural
gas, refinery off-gas, LPG, naphtha. Product is hydrogen (H2), carbon monoxide (CO),
syngas or a combination thereof with co-product steam and optionally carbon dioxide.
Description
Capacities per SMR train are 15,000Nm3/h–200,000 Nm3/h of H2, 3,500
Nm3/h–40,000 Nm3/h of CO and up to 350,000 Nm3/h of syngas.
Feedstocks are desulfurized, mixed with steam and pre-heated. Optionally a
catalytic pre-reforming step may be foreseen to convert the feed/steam mixture to a
methane-rich gas to improve the efficiency of the SMR. The main reforming reaction
takes place in the proprietary top-fired steam reformer in which the feed/steam
mixture is converted while passing catalyst-filled and heated tubes at temperatures
of 800°C–40°C and pressures of 15 barg–45 barg. Reformed gas leaving the reformer
contains H2, CO, CO2 and unreacted components.
Efficiency of the process and composition of the reformed gas can be adjusted
via the process parameters reforming pressure, temperature and steam-to-feed ratio.
In case the H2 yield should be increased or maximized, a catalytic shift reactor may
be added and fed with reformed gas to convert CO and steam to additional H2 and
CO2. In case a high CO yield is targeted, CO2 may be separated from reformed gas and
recycled to the SMR. Additional import CO2 may be added, if available. Suitable product
purification technologies include: PSA and membrane for H2, amine wash (aMDEA) for
CO2 removal and methane wash Cold Box for CO.
Advantages
Flexibility in process design to optimize for best efficiency, lowest CAPEX
or lowest total cost of ownership. Optimized integration of refinery-off gases for
H2 production and recovery. Best-in-class plant reliability and operability through
operational feedback from Air Liquide own plants.
Economics
OPEX:
H2 plants (based on natural gas feed & fuel):
Steam co-export ratio: 0.4 to 1.1 kg/Nm3 H2
Feed + Fuel: 14.5 MJ/Nm3–15.3 MJ/Nm3 H2
HP steam
Heat
recovery
Process steam
Flue gas
Fuel gas
Natural gas
H2
Tail gas
Reformer
Hydrodesulfurization
pretreatment
Syngas
Co-shift
Prereformer
Boiler feed
water
Syngas
cooling
HyCO plants (based on natural gas feed & fuel):
H2/CO product ratio: 2.6 to 4.2
Steam co-export ratio: 0.3 to 0.7 kg/Nm3 [H2 + CO]
Feed and Fuel: 14.2 MJ/Nm3–14.8 MJ/Nm3 [H2+CO]
CAPEX:
H2 and HyCO plants (incl. purification): 20 to 300 mm Euro
Installations
More than 140 installations, with more than 40 in the last 20 years.
Website
www.engineering-airliquide.com/hydrogen
Contact
hydrogen@airliquide.com
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COMPANY INDEX
Hydrogen Generation—SMR-X™
Zero Steam Production
Flue gas
Application
Production of hydrogen (H2 ), without coproducing steam, in a radiative heat
exchange steam methane reformer (SMR).
Feedstock is natural gas, refinery offgas, LPG or naphtha. Product is H2
with zero steam coproduct.
Description
SMR-X technology is based on a new generation steam methane reformer
furnace with additional heat recovery of the reformed gas leaving the reaction zone
back to the catalyst bed. This is achieved via heat exchange tubes located inside the
main reformer tubes which the reformed gas has to pass before leaving the reformer.
Geometry and material of the internal heat exchange system is optimized for
high efficiency and reliability. Consequently utilization of SMR-X allows for a H2 plant
design with balanced steam production and consumption at superior overall process
efficiency compared to conventional SMR technology. Also highly efficient H2 plant
designs with very low steam co-export ratios are possible.
HP steam
Heat
recovery
Process steam
Flue gas
Fuel gas
Natural gas
H2
Tail gas
Prereformer
Hydrodesulfurization
pretreatment
H2 product
Co-shift
Reformer
Boiler feed
water
PSA
Advantages
The plant’s steam system is simplified and the reformer size of SMR-X is reduced
compared to a conventional furnace, because approximately 20% of the required
process heat is supplied by internal heat exchange.
Economics
OPEX: Feed + fuel: ~13.6 MJ/Nm3 H2 (figures based on natural gas)
CAPEX: 20 to 110 MM Euro
Licensor
Air Liquide Engineering & Construction
Website
www.engineering-airliquide.com/hydrogen
Contact
hydrogen@airliquide.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—
Steam methane reformer (SMR)
S-removal
Prereformer
Radiant wall reformer
CO shift reactor
PSA
Steam export
Application: Production of hydrogen (H2 ) from hydrocarbon feedstocks such as
natural gas, LPG, butane, naphtha, refinery off gases, etc., using the Haldor Topsoe
radiant-wall Steam Methane Reformer (SMR). Plant capacities range from 5 MNm³/h
to more than 200 MNm³/h H2 (>200+ MMscfd H2 ) and H2 purity of up to 99.999+%.
Description: Haldor Topsoe’s SMR-based H2 plants can be tailored to suit the
customer’s needs with respect to feedstock flexibility and steam export. In a typical
H2 plant, the hydrocarbon feedstock is desulfurized and, subsequently, process steam
is added, and then the mixture is fed to a pre-reformer. Further reforming is done
in the Topsoe radiant wall SMR. Subsequently, process gases are reacted in a watergas shift reactor and purified by the pressure swing absorption (PSA) unit to obtain
product-grade H2 . PSA off gases are used as fuel in the SMR. Excess heat in the plant
is efficiently used for process heating and steam generation. The SMR operates at
high outlet temperatures up to about 950°C (1,740°F), while the Topsoe reforming
catalysts enable low steam-to-carbon ratios. Both conditions (advanced steam
reforming) are necessary for high-energy efficiency and low H2 production costs.
Feed
H2
Flue gas
Combustion air
BFW
Fuel gas
Installations: Topsoe’s reforming technology is in operation in more than
250 industrial plants worldwide.
References:
1. Gol, J. N. et al., “Options for hydrogen production,“ HTI Quarterly, Summer 1995.
2. Rostrup-Nielsen, J. R. and T. Rostrup-Nielsen, “Large-scale hydrogen production,”
CatTech, Vol. 6, No. 4., 2002.
3. Rostrup-Nielsen, T., “Manufacture of hydrogen“ Catalysis Today, Vol. 105, 2005.
Licensor: Haldor Topsoe A/S
Website: www.topsoe.com/processes/hydrogen
Contact: tlys@topsoe.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—
Steam Methane Reforming
Fuel
HP steam
Hydrogen
Application: Production of hydrogen (H2 ) for use in refining processes from
hydrocarbon feedstocks—such as natural gas, liquefied petroleum gas (LPG), refinery
off-gases and naphtha—using the steam-methane-reforming (SMR) process.
Description: The basic process steps are hydro-desulfurization of feedstock; steam
reforming; heat recovery from reformed and combustion flue gas to produce, process
and export steam; single-stage adiabatic high-temperature CO-shift conversion
(alternative shift concepts possible for plant optimization); and final H2 purification
by pressure swing adsorption (PSA).
Process options with pre-reforming for overall plant optimization—fuel savings
over standalone primary reformer, reduced capital cost of the reformer, higher
primary reformer preheat temperatures, increased feedstock flexibility, lower
involuntary steam production and lower overall steam/carbon ratios—are possible.
The reformer furnace has a compact firebox with vertical hanging catalyst tubes
arranged in multiple, parallel rows. Forced draft top-firing burners are integrated into
the fire box ceiling. Compared to other designs, the burner trimming and individual
adjustment to achieve a uniform heat flow pattern throughout the reformer cross
section are substantially improved. Concurrent firing ensures a uniform temperature
profile throughout the reformer tube length. Flame and stable combustion flow pattern
are supported by flue-gas collecting channels arranged at ground level between the
hot reformed gas headers. Thermal expansion, as well as tube and catalyst weight, are
compensated by an adjustable spring hanger system arranged inside the penthouse,
removing mechanical stress from the hot manifold outlet headers at ground level.
The radiant reformer box is insulated with multiple layers of ceramic fiber blanket
insulation that is mechanically stable and resistant to thermal stress.
Convection section: Depending on H2 product capacity, the convection
section (a series of serial heat exchanger coils) is arranged either vertically with
an induced-draft (ID) flue gas fan and a stack at reformer burner level, or (specifically
for higher capacity units) horizontally at ground level for ease of access and reduced
structural requirements.
H2 product can be purified with Linde´s highly efficient PSA process. H2 product
purities up to 99.9999 mol% are possible.
Advantages:
• A minimized number of forced draft top-firing burners integrated into the
firebox ceiling improves burner trimming and individual adjustment to achieve
a uniform heat flow pattern throughout the reformer cross section.
Combustion
air
Feed
LP steam
DMW
• Concurrent firing ensures a uniform temperature profile throughout the reformer
tube length. Flame and stable combustion flow pattern are supported by the
flue gas-collecting channels arranged at ground level between the hot reformed
gas headers.
Economics: Performance:
Hydrogen product
Flow rate Nm3/h
MMscfd
Pressure, bara
Purity, mol%
Export steam
Flow rate, ton/hr
Temperature, °C
Pressure, bara
Natural gas
LPG
Naphtha
Refinery gas
50,000
44.8
25
99.9
50,000
44.8
25
99.9
50,000
44.8
25
99.9
50,000
44.8
25
99.9
31
390
40
28.9
390
40
28.6
390
40
29.2
390
40
Continued 
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydrogen Generation—Steam Methane Reforming (cont.)
Natural gas
LPG
Feed and fuel consumption
GCal/hr
177.8
181.8
GJ/hr
744.4
761.2
Energy consumption (including steam credit)
Gcal/1,000 Nm3 H2
3.07
3.21
Gj/1,000 Nm3 H2
12.853
13.44
Naphtha
Refinery gas
182.9
765.8
175.8
736
3.222
13.49
3.072
12.862
Investment: Steam methane reforming is the most cost-effective method of H2
production, due to readily available and inexpensive feedstocks, time to end product,
and efficiency (approximately 75%–80%).
Installations: More than 200 Linde-designed and supplied plants have been
constructed worldwide.
References:
1. Shahani, G., W. Schoerner and N. Musich, “Selecting the right steam methane
reformer: Can vs. box design,” Hydrocarbon Processing, December 2011.
Licensor: Linde AG.
Website: www.leamericas.com/hydrogen
Contact: www.leamericas.com/en/contact
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydrogen Generation—
Terrace Wall™ reformer
Application: Manufacture hydrogen (H2 ) for hydrotreating, hydrocracking or other
refinery or chemical use.
Description: H2 is produced by steam reforming of hydrocarbons, followed by
the purification by pressure swing adsorption (PSA). Feed is heated (1) and then
hydrogenated (2) over a cobalt-molybdenum catalyst bed, followed by purification
(3) with zinc oxide (ZnO) to remove sulfur. The purified feed is mixed with steam
and preheated further, then reformed over nickel catalyst in the tubes of the
reforming furnace (1).
Amec Foster Wheeler’s Terrace Wall reformer is an advanced design combining
high efficiency with ease of operation and reliability. Other designs are also available
on the market, depending on project requirements. Combustion air preheating is
typically used to reduce fuel consumption and utility steam export.
Pre-reforming can be used upstream of the reformer if a mixture of naphtha
and light feeds are used, or if steam export must be minimized. The syngas from
the reformer is cooled by generating steam, then reacted in the shift converter (4),
where carbon monoxide (CO) reacts with steam to form additional H2 and carbon
dioxide (CO2 ).
In the PSA section (5), impurities are removed by solid adsorbent. For
regeneration of the adsorbent beds, adsorbed gases are depressurized and purged
in a semi-batch operation. Purge gas from the PSA section, containing CO2 , methane
(CH4 ), CO and some H2 , is used as fuel in the reforming furnace. Heat recovery from
reformer flue gas may be achieved via combustion air preheating or additional steam
generation. Other variations include a scrubbing system to recover flue gas CO2 .
Operating conditions: Typical H2 purity of 99.9%; pressure of 300 psig, with utility
steam and/or CO2 as byproducts. High-pressure units (> 700 psig) may be used
in specific applications.
Yields: Light saturated hydrocarbons such as refinery gas or natural gas, liquefied
petroleum gas (LPG) or light naphtha are used as feedstock without any constraint
on the yield. Single-train capacities are available up to 200 MMscfd.
Advantages: The Amec Foster Wheeler process utilizes a highly efficient design,
making it the most economical process for medium and large hydrogen production
units. The proprietary Terrace WallTM steam reformer design provides leading
reliability and operability.
Hydrocarbon feed
1
Steam
Steam
2
4
Steam
5
Product hydrogen
3
Purge gas
Fuel gas
Economics:
Investment: 4 MMscfd–200 MMscfd, 1Q 2017, US Gulf Coast (USGC);
$7 MM–$200 MM
Utilities, 50 MMscfd unit basis:
Air preheat case Steam generation case
Natural gas, feed + fuel, MM Btu/h
755
905
Export steam at 600 psig/700°F, lb/h
70,000
170,000
Boiler feed water, lb/h
125,000
225,000
Electricity, kW
650
250
Cooling water, gpm (18°F rise basis)
200
200
Development/Delivery: The Amec Foster Wheeler H2 production process
is a well-referenced and fully commercialized technology.
Installations: More than 150 plants, ranging from less than 4 MMscfd to 200 MMscfd
in a single train, with numerous multi-train installations.
References: Handbook of Petroleum Refining Processes, 4th Ed., pp. 211–236,
McGraw-Hill, 2016.
Licensor: Amec Foster Wheeler
Website: www.amecfw.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydroprocessing—CDHydro®,
CDHDS®, CDHDS+®
CDHydro column
Application: The CDHydro®, CDHDS® and CDHDS+® processes are used to selectively
desulfurize FCC gasoline with minimum octane loss.
Products: Ultra-low-sulfur FCC gasoline with maximum retention of 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 fractionation of the light naphtha overhead in a CDHydro
column. Mercaptan sulfur reacts with excess diolefins to produce heavier sulfur
compounds, and the remaining diolefins are partially saturated to olefins by reaction
with hydrogen. Bottoms from the CDHydro column, containing heavier sulfur
compounds, are fed to the CDHDS column where the MCN and HCN are catalytically
desulfurized in two separate zones. HDS conditions are optimized for each fraction
to achieve the desired sulfur reduction with minimal olefin saturation. Olefins are
concentrated at the top of the column, where conditions are mild, while sulfur is
concentrated at the bottom where the conditions result in very high levels of HDS.
No cracking reactions occur at the mild conditions, so yield losses are easily
minimized with vent-gas recovery. The three product streams are stabilized
together or separately, as desired, resulting in product streams appropriate
for their subsequent use. The two columns are heat integrated to minimize energy
requirements. Typical reformer hydrogen can be used in both columns without
makeup compression. The sulfur reduction achieved will allow the blending
of gasoline that meets current and future regulations.
A second stage of desulfurization is required after H2S stripping when sulfur
conversion targets are high or, optionally, when higher octane retention is warranted.
This version, the CDHDS+ process, targets the remaining concentration of sulfur
compounds from the CDHDS column, ensuring that the final product specification
is achieved.
Catalytic distillation essentially eliminates catalyst fouling because the
fractionation removes heavy-coke precursors from the catalyst zone before coke
can form and foul the catalyst pores. Thus, catalyst life in catalytic distillation
CDHDS
column
H2S
stripper
LCN
CDHDS+
reactor
Stabilizer column
Treated gasoline product
FCC
gasoline
MCN
HCN
Makeup
hydrogen
is increased significantly beyond typical fixed-bed life. The CDHydro/CDHDS units
can operate through up to three FCC cycles without requiring a shutdown
to regenerate or to replace catalyst.
Economics: The estimated ISBL capital cost for a 50,000-bpd CDHydro/CDHDS unit
with 95% desulfurization is $40 MM (2005 US Gulf Coast).
Installation: There are 54 CDHydro/CDHDS/CDHDS+ desulfurization units
commercially licensed to treat FCC gasoline, of which seven are now in engineering/
construction. Total licensed capacity exceeds 1.8 MMbpd.
Licensor: Lummus Technology, a CB&I company
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COMPANY INDEX
Hydroprocessing—CDHydro®
Hydrogenation
Hydrogen recycle
CW
Application: The CDHydro process is used to selectively hydrogenate di-olefins
in the top section of a hydrocarbon distillation column. Additional applications,
including mercaptan removal, hydroisomerization and hydrogenation of olefins
and aromatics, are also available.
Description: The patented CDHydro process combines fractionation with
hydrogenation. Proprietary devices containing catalyst are installed in the
fractionation column’s top section (1). Hydrogen (H2 ) is introduced beneath the
catalyst zone. Fractionation carries light components into the catalyst zone where
the reaction with hydrogen occurs. Fractionation also sends heavy materials to
the bottom. This prevents foulants and heavy catalyst poisons in the feed from
contacting the catalyst. In addition, clean hydrogenated reflux continuously washes
the catalyst zone. These factors combined provide a long catalyst life.
Additionally, mercaptans can react with di-olefins to make heavy, thermallystable sulfides. The sulfides are fractionated to the bottoms product. This can
eliminate the need for a separate mercaptan removal step. The distillate product
is ideal feedstock for alkylation, etherification or olefins conversion processes.
The heat of reaction evaporates liquid, and the resulting vapor is condensed in
the overhead condenser (2) to provide additional reflux.
The natural temperature profile in the fractionation column results in a virtually
isothermal catalyst bed rather than the temperature increase typical of conventional
reactors.
The CDHydro process can operate at much lower pressure than conventional
processes. Pressures for the CDHydro process are typically set by the fractionation
requirements. Additionally, the elimination of a separate hydrogenation reactor
and H2 stripper offers significant capital cost reduction relative to conventional
technologies. Feeding the CDHydro process with reformate and light-straight run
for benzene saturation provides the refiner with increased flexibility to produce
low-benzene gasoline. Isomerization of the resulting C5 /C6 overhead stream
provides higher octane and yield due to reduced benzene and C7+ content compared
to typical isomerization feedstocks.
Hydrogen
1
Offgas
2
Depentanizer
FCC C +
4
MP steam
Reflux
Treated FCC C4s
FCC C5+ gasoline
capital cost of the column is only 5%–20% more than for a standard column,
depending on the CDHydro application. Elimination of the fixed-bed reactor
and stripper can reduce capital cost by as much as 50%.
Installation: More than 100 CDHydro units are commercially licensed for C4, C5,
C6, LCN and benzene hydrogenation applications. Forty units have been in operation
for more than 10 years, and total commercial operating time now exceeds 500 years
for CDHydro technologies. Eleven units are presently in engineering/construction.
Licensor: Lummus Technology, a CB&I company
Economics: Fixed-bed hydrogenation requires a distillation column followed by
a fixed-bed hydrogenation unit. The CDHydro process eliminates the fixed-bed unit
by incorporating catalyst in the column. When a new distillation column is used,
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydroprocessing—
Fuel Gas Hydrotreatment (FGH)
Application: Haldor Topsoe’s Fuel Gas Hydrotreatment process is applied for
purification of refinery fuel gases containing difficult-to-remove sulfur species and
(di-)olefins. All sulfur species are converted to hydrogen sulfide (H2S) for subsequent
removal, and olefins are saturated. The purified gas can be used as valuable feed
for instance in hydrogen generation. Purified fuel gas satisfies even the strictest
environmental requirements, typically below 10 parts per million (ppm) total sulfur.
Description: Topsoe’s Fuel Gas Hydrotreatment is usually a once-through process,
in its simplest form with a single reactor. Topsoe’s catalysts are highly active and
selective, enabling hydrotreatment at low partial pressures of hydrogen (H2), often
requiring no addition of H2 as the fuel gas H2 content is sufficient to drive the process.
For more demanding refinery fuel gases and/or stricter product specifications,
the core hydrotreatment can be supplemented with a di-olefin saturation
pre-treatment reactor and/or COS hydrolysis utilizing a very selective catalyst
(no mercaptan recombination).
The highly active catalysts enable hydrotreatment at low pressures often
seen in fuel gas systems, and the very difficult sulfur species are converted to H2S
for downstream removal. No H2S removal is required before the FGH unit—the
H2S (typically 10%–15%) passes through and all of the H2S is removed in a single
downstream amine wash. Only one amine wash is required, and if an existing wash
is repurposed, the investment is limited.
Operating conditions: Although the hydrotreatment processes are favored by higher
pressures, it is often possible to operate at the low typical fuel gas pressures in the
order of 10 barg. Temperatures are below 400°C. Combined with simple adiabatic
reactors, equipment costs are kept at a minimum. No regeneration is required,
so the unit has an extremely high availability.
Yields: As non-H2S sulfur species typically constitute less than 1,000 ppm (0.1%),
only a very small amount of H2 is consumed for sulfur treatment. Olefins in
the percent range require more H2 for saturation, but the total yield is high.
Advantages: The FGH process is simple with low investment cost and very low
catalyst cost, while being highly efficient in desulfurization. Fuel gas is converted
into valuable feed gas, and even the strictest environmental requirements are met.
The unit is simple and robust to operate.
Hydrogenator
Hydrolyzer
H2O
Alkenes
Organo-sulfur
compounds
COS
hydrolysis
To separator + amine wash
(H2)
Fuel gas
Investment: From $5 MM for 50 MNm3/h, depending on configuration.
Utilities: A typical FGH unit utilizes the H2 already present in the fuel gas.
A small amount of steam may be needed for hydrolysis. Unless the olefin level
is high, no recycle is required. In some cases a feed compressor and/or a recycle
compressor is needed, requiring some power.
Development/Delivery: Topsoe has been providing engineering process design
and catalysts for hydrotreatment for decades, collaborating with EPC’s for complete
solutions.
Installations: Topsoe has designed and licensed more than 150 hydroprocessing units,
and delivered catalysts for more than 500 units, for naphtha, diesel, VGO and fuel gas.
References: Specifically for FGH, a large unit has been operational at a major US
refinery for more than 3 yr. Other units are at varying stages of construction.
Licensor: Haldor Topsoe A/S, Sustainables Business Unit.
Website: info.topsoe.com/refinery-fuel-gas-purification
Contact: JEMP@topsoe.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydroprocessing—
Hydrodearomatization
Application: Haldor Topsoe’s two-stage hydrodesulfurization/hydrodearomatization
(HDS/HDA) process is designed to produce low-aromatics distillate 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. The initial hydrotreating step,
or the “first stage” of the two-stage reaction process, is similar to conventional
Topsoe hydrotreating. The process uses a Topsoe high-activity base metal catalyst,
such as TK-611 HyBRIM™, to perform deep desulfurization and deep denitrification
of the distillate feed. Liquid effluent from this first stage is sent to an intermediate
stripping section, in which hydrogen sulfide (H2S) and ammonia are removed using
steam or recycle hydrogen. Stripped distillate is sent to the final hydrotreating reactor,
or the “second stage.” In this reactor, distillate feed undergoes saturation of aromatics
using a Topsoe noble metal catalyst (either TK-907/TK-911 or TK-915), a high-activity
dearomatization catalyst. Finally, the desulfurized, dearomatized distillate product
is steam stripped in the product stripping column to remove H2S, dissolved gases
and a small amount of naphtha formed. Like the conventional Topsoe hydrotreating
process, the HDS/HDA process uses Topsoe’s graded bed loading and high-efficiency
patented reactor internals to provide optimum reactor performance and catalyst
use leading to the longest possible catalyst cycle lengths. Topsoe’s graded-bed
technology and the 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 20 barg–60 barg
(300 psig–900 psig), and typical operating temperatures range from 320°C–400°C
(600°F–750°F) in the first stage reactor, and from 260°C–330°C (500°F–625°F)
in the second stage reactor.
Makeup hydrogen
Recycle gas
compressor
Diesel feed
HDS
separator
Wash water
First
stage
Amine
scrubber
HDS
stripper
HDS
reactor
Overhead vapor
HDS
stripper
Water
Sour
water
Wild naphtha
Second
stage
Product
diesel
stripper
HDA
reactor
Steam
Diesel product
HDA
separator
Diesel cooler
References:
1. de la Fuente, E. P. Christensen and M. Johansen, “Options for meeting EU
year 2005 fuel specifications,” 4th ERTC, Paris, November 1999.
2. Ghiyati, Y., “Technology options for LCO upgrading,” ME-TECH, Dubai,
January 2011.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com
Contact: mkj@topsoe.com
Installations: A total of 9 units.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—HydroFlex™
Application: Topsoe’s environmentally sustainable HydroFlex technology gives
refiners the ability to make the shift by converting renewable feedstocks into drop-in,
ultra-low sulfur gasoline, jet fuel or diesel. The process offers total feedstock flexibility
for treating biologically-derived materials, such as tall oil, palm oil, corn oil, rapeseed
oil, pyrolysis oil and tallow.
Description: Topsoe’s HydroFlex technology produces synthetic diesel that is fully
compatible with today’s energy infrastructure and meets both ASTM 975 and EN 590
specifications. In fact, renewable diesel is often superior to fossil-based diesel in terms
of cetane number and sulfur content. Therefore, it provides the opportunity to blend it
with lower grade fossil diesel cuts to increase their value. Renewable fuels have several
advantages over first-generation fuels, such as fatty acid methyl esters (FAME) and
conventional fuels.
HydroFlex is configured to individual project constraints and objectives
for hydrotreating any renewable oil, and can be deployed in both grassroots units
and revamps for co-processing or stand-alone applications.
Installations: Total of four units. Topsoe renewable catalysts have been supplied
to 18 units.
Offgas and naphtha
Bio material
Reactor loop
Fractionation
Recycle
Renewable diesel
Typical stand-alone HydroFlex configuration for processing of renewable feeds
Offgas and naphtha
Bio material
Fossil gasoil
Reactor loop
Fractionation
Renewable diesel
Typical stand-alone HydroFlex coprocessing for processing of renewable and fossil feeds
References:
1. R. G. Egeberg, N. H. Michaelsen and L. Skyum, “Novel hydrotreating technology
for production of green diesel”, ERTC, Berlin, November 2009.
2. R. G. Egeberg, N. H. Egeberg, S. Nyström, U. Kuylenstierna and K. Efraimsson,
“Turning over a new leaf in renewable diesel hydrotreating”, NPRA Annual
Meeting, Phoenix, Arizona, March 2010.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/processes/unconventional-feeds
Contact: mkj@topsoe.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Hydroprocessing—Hydrogenation,
CDHydro® benzene in reformate
Hydrogen recycle
CW
Offgas
Application: The CDHydro catalytic distillation technology processes reformate
streams from refineries to reduce benzene to levels required by low-benzene gasoline
specifications.
Description: The patented CDHydro process hydrogenates benzene to cyclohexane
in a catalytic distillation column. Hydrogenation reduces benzene in the gasoline
pool. This process combines the three unit operations of reformate splitter, benzene
hydrogenation and product stabilization in one unit operation.
Selective hydrogenation: Reformate and hydrogen (H2 ) are fed to the catalytic
distillation column. Hydrogenation of benzene to cyclohexane can exceed 99%.
Benzene conversion can easily be limited to lower levels through control of
H2 addition. Washing action of the reflux minimizes oligomer formation, flushes
heavy compounds from the catalyst and promotes long catalyst life. Treated C6
product is taken as overhead. Excess H2 and lights are recycled and vented from
the overhead drum. The C7+ product is taken as bottom with essentially full recovery
of heavy aromatics.
The unique catalytic distillation column combines reaction and fractionation
in a single unit operation. This constant-pressure boiling system ensures precise
temperature control in the catalyst zone. Low reaction temperature and isothermal
operation enhance safety.
Economics: Capital costs are considerably lower than conventional hydrotreaters,
since the single-column design eliminates costs associated with fixed-bed systems
and operates at low enough pressure to avoid the need for a hydrogen compressor.
The CDHydro process is typically installed in a benzene-toluene splitter, either as
a retrofit or in a new column.
Advantages:
• Lower capital cost
• High conversion
• Simple operation
• Low operating pressure
Overhead
drum
Low-pressure hydrogen
C5 – C9 reformate
Reflux
Treated C6s
Benzene-toluene
splitter
MP steam
C7 +
•
•
•
•
•
•
•
Low benzene reformate
Low operating cost
Low capital cost
Low benzene in reformate
All carbon steel construction
No H2 compressor
Isothermal operation
Reduced plot area.
Installation: There are seven licensed units, with the first one licensed in 1995.
Licensor: Lummus Technology, a CB&I company
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Hydroprocessing—Hydrogenation,
CDHydro® selective for refinery
C4 feeds
Application: To process C4 streams from refineries to produce a stream with
high butylenes content that is essentially butadiene-free, suitable for methyl
tertiary butyl ether (MTBE) production, butene-1 production or alkylation feed.
Description: The patented C4 CDHydro process achieves selective hydrogenation
of butadiene to n-butenes in a catalytic distillation column. Selective hydrogenation
increases butenes available for alkylation or isomerization, reduces acid consumption
in alkylation units, and greatly improves the quality of HF alkylate. The process uses
commercially available catalyst in proprietary catalytic distillation structures.
The unique catalytic distillation column combines reaction and fractionation
in a single unit operation. This constant pressure boiling system ensures precise
temperature control in the catalyst zone. Low reaction temperature and isothermal
operation enhance selectivity and minimize yield losses to paraffins. Isomerization
of butene-1 to butene-2 can be maximized to improve alkylate quality on HF units or
minimized for increased butene-1 recovery.
Refinery C4 streams are combined with hydrogen (H2 ) in the catalytic column.
Treated C4 products are taken overhead. The washing action of the reflux minimizes
oligomer formation, flushing heavy compounds from the catalyst and promoting long
catalyst life. Excess H2 and lights are vented from the overhead drum.
Economics: Capital costs are considerably lower than conventional hydrotreaters,
since the single column design eliminates costs associated with fixed-bed systems.
The C4 CDHydro process is typically installed in a debutanizer, either as a retrofit or in
a new column.
CW
Offgas
Overhead
drum
Low-pressure hydrogen
Treated C4s
C4+
Reflux
LP steam
C5+
• All carbon steel construction
• Isomerization option
• No H2 compressor.
Installation: There are more than 110 total commercially licensed CDHydro units.
Licensor: Lummus Technology, a CB&I company
Process advantages include:
• Low operating pressure
• Low operating cost
• High product yield (low paraffin make)
• No polymer recycle across catalyst
• No sweetening required
• Essentially mercaptan sulfur-free distillate product
• Flexible butene-1/butene-2 ratio
• Retrofit to existing C4 columns
Copyright © 2017 Gulf Publishing Company. All rights reserved.
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Hydroprocessing—Hydrogenation,
CDHydro® selective for refinery
C5 feeds
Application: To process C5 streams from refineries to produce a stream with
high isoamylenes content that is essentially free of diolefins. The treated C5 stream
is suitable for tertiary amyl methyl ether (TAME) production or alkylation feed.
Description: The patented C5 CDHydro process achieves selective hydrogenates
diolefins to amylenes in a catalytic distillation column. Selective hydrogenation is
a required pretreatment step for TAME production and C5 alkylation, improving
product quality in both and reducing acid consumption in the latter.
The process uses commercially available catalyst in proprietary catalytic
distillation structures. The unique catalytic distillation column combines reaction
and fractionation in a single unit operation. This constant pressure boiling system
ensures precise temperature control in the catalyst zone. Low reaction temperature
and isothermal operation enhance selectivity and minimize yield losses to paraffins.
Non-reactive 3-methyl butene-1 is isomerized to reactive 2-methyl butene-2, which
increases potential TAME production. Pentene-1 is isomerized to pentene-2, which
improves octane number.
The refinery C5 streams and/or hydrotreated pygas are combined with hydrogen
(H2 ) in the catalytic column. Treated C5 products are taken overhead. The washing
action of the reflux minimizes oligomer formation, flushing heavy compounds from
the catalyst and promoting long catalyst life. The catalyst will react acidic sulfur
compounds with diolefins to form heavy compounds, which exit in the tower bottoms.
The distillate product is essentially mercaptan-sulfur-free.
Economics: Capital costs are considerably lower than conventional hydrotreaters,
since the single column design eliminates costs associated with fixed-bed systems.
Additionally, the ability to remove acidic sulfur compounds eliminates the need
for sweetening. The C5 CDHydro process is typically installed in a depentanizer,
either as a retrofit or in a new column.
CW
Offgas
Overhead
drum
Low-pressure hydrogen
Treated C5s
Light cat naphtha
Reflux
LP steam
C6+
•
•
•
•
•
•
•
No sweetening required
Essentially mercaptan sulfur-free distillate product
Flexible butene-1/butene-2 ratio
Retrofit to existing C4 columns
All carbon steel construction
Isomerization option
No H2 compressor.
Installation: There are more than 100 total commercially licensed CDHydro units.
Licensor: Lummus Technology, a CB&I company
Process advantages include:
• Low operating pressure
• Low operating cost
• High product yield (low paraffin make)
• No polymer recycle across catalyst
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Hydroprocessing—Hydrogenation,
selective for MTBE/ETBE C4 raffinates
MTBE/ETBE debutainzer
CW
Offgas
Application: To achieve selective hydrogenation of butadiene to n-butenes in
a catalytic distillation column.
Description: The C4 CDHydro® catalytic distillation technology processes C4 streams
from refineries or steam crackers within a methyl tertiary butyl ether (MTBE)/ethyl
tertiary butyl ether (ETBE) debutanizer to produce a raffinate with a high butylenes
content that is essentially butadiene-free. After methanol recovery, the treated C4
raffinate can be used for butene-1 production or alkylation feed.
Selective hydrogenation increases butenes available for alkylation or
isomerization, reduces acid consumption in alkylation units, and greatly improves
the quality of HF alkylate. The process uses commercially available catalyst in
its proprietary catalytic distillation structures (CDModules®).
The C4 stream is combined with hydrogen (H2 ) in the MTBE/ETBE debutanizer.
Treated C4 raffinate is taken overhead. The washing action of the reflux minimizes
oligomer formation, flushing heavy compounds from the catalyst and promoting
long catalyst life. Excess H2 and lights are vented from the overhead drum.
The catalyst is sulfur tolerant.
Process advantages include:
• Low capital cost
• Low catalyst requirements
• Low operating cost
• High product yield (low saturation to paraffins)
• No polymer recycle across catalyst
• Use of reaction heat
• Sulfur-tolerant catalyst
• Essentially mercaptan-sulfur-free distillate product
• Flexible butene-1/butene-2 ratio
• Retrofit to existing C4 columns
• All carbon steel construction.
Overhead
drum
Hydrogen
C4s with MTBE/ETBE and methanol/ethanol
Reflux
Treated C4s raffinate
LP steam
MTBE/ETBE
Economics: Capital costs are considerably lower than conventional hydrotreaters,
since the single column design eliminates costs associated with fixed-bed systems.
The C4 CDHydro process is typically installed in a conventional or catalytic
MTBE/ETBE debutanizer, either as a retrofit or in a new column.
Installation: There are more than 100 total commercially licensed CDHydro units.
Licensor: Lummus Technology, a CB&I company
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2017 REFINING PROCESSES HANDBOOK
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Hydroprocessing—Hydrotreating
Makeup hydrogen
Application: Haldor Topsoe’s hydrotreating technology has a wide range of
applications, including the purification of naphtha, distillates and residue, as well as
the deep desulfurization and color improvement of diesel fuel and pretreatment
of FCC and hydrocracker feedstocks.
Furnace
Products: Ultra-low-sulfur diesel fuel, and clean feedstocks for FCC and
hydrocracker units.
Description: Topsoe’s hydrotreating process design incorporates our industrially
proven high-activity TK catalysts with optimized graded-bed loading and highperformance, patented reactor internals. The combination of these features and
custom design of grassroots and revamp hydrotreating units result in process
solutions that meet the refiner’s objectives in the most economical way. In the Topsoe
hydrotreater, feed is mixed with hydrogen (H2), heated and partially evaporated in
a feed/effluent exchanger before it enters the reactor. In the reactor, Topsoe’s highefficiency internals have a low sensitivity to unlevelness and are designed to ensure
the most effective mixing of liquid and vapor streams and the maximum utilization
of the catalyst volume. These internals are effective at a high range of liquid loadings,
thereby enabling high turndown ratios. Topsoe’s graded-bed technology and the use
of shape-optimized inert topping and catalysts minimize the build-up of pressure
drop, thereby enabling longer catalyst cycle length. The hydrotreating catalysts
themselves are of the Topsoe TK series, and have proven their high activities and
outstanding performance in numerous operating units throughout the world. The
reactor effluent is cooled in the feed-effluent exchanger, and the gas and liquid are
separated. The H2 gas is sent to an amine wash for removal of hydrogen sulfide and
is then recycled to the reactor. Cold H2 recycle is used as quench gas between the
catalyst beds, if required. The liquid product is steam stripped in a product stripper
column to remove hydrogen sulfide, dissolved gases and light ends.
Operating conditions: Typical operating pressures range from 20 barg to 80 barg
(300 psig to 1,200 psig), and typical operating temperatures range from 320°C to 400°C
(600°F to 750°F).
Installations: More than 150 Topsoe hydrotreating units for the various applications
above are in operation or in the design phase.
Recycle gas
compressor
Absorber
Lean amine
Reactor
Rich amine
H2 rich gas
Fresh feed
Products to
fractionation
High-pressure
separator
Low-pressure
separator
References:
1. Cooper, B. H. and K. G. Knudsen, “Production of ULSD: Catalyst, kinetics and
reactor design,” World Petroleum Congress, 2002.
2. Patel, R. and K. G. Knudsen, “How are refiners meeting the ultra-low-sulfur diesel
challenge,” NPRA Annual Meeting, San Antonio, March 2003.
3. Topsoe, H., K. Knudsen, L. Skyum and B. Cooper, “ULSD with BRIM catalyst
technology,” NPRA Annual Meeting, San Francisco, March 2005.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/processes/hydrotreating
Contact: mkj@topsoe.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—Hydrotreating
Application: Hydrotreating is an established refinery process for reducing sulfur,
nitrogen and aromatics while enhancing cetane number, density and smoke point.
This is especially critical for refiners that are looking to process heavier feedstocks,
produce cleaner fuels and extend cycle length. Shell Global Solutions’ hydrotreating
processes are particularly effective for full-range middle distillate hydrotreating
(naphtha, kerosine and gasoil) and vacuum gasoil (VGO) applications. In conjunction
with Criterion Catalysts & Technologies, Shell offers a portfolio of high-performing
catalysts, allowing refiners to make the most of state-of-the-art reactor internals.
Shell also has proven technology on distillate dewaxing application that enables
refiners to increase their production of winter diesel (exhibiting excellent cold-flow
properties, specifically cloud point).
Description: Although capable of many configurations, this process focuses on
causing oil fractions to react with hydrogen (H2 ) in the presence of a catalyst to
produce high-value, clean products. The heart of Shell Global Solutions’ hydrotreating
technology is the reactor section, which features a pressurized reactor vessel utilizing
proprietary catalyst and reactor internals hardware. Beginning with highly effective
particulate filters installed in the reactor dome, Shell is able to mitigate pressure
drop and maldistribution to the catalyst bed. These filters also optimize active
catalyst volume and prevent channeling to subsequent vapor-liquid distribution trays,
in turn ensuring nearly 100% catalyst wetting.
To increase thermal control, Shell installs an Ultra-Flat-Quench (UFQ) deck at the
bottom of the bed for mixing reactants with cold quench gas and redistributing them
to the next bed. The compact design of these internals allows for decreased reactor
height for grassroots construction, or up to a 20% increase in catalytic volume
for multi-bed revamps. Shell’s integrated stripper design, which is fully proven
in commercial operations, combines a hot-low pressure separator (HLPS) and
a cold-low pressure separator (CLPS), thereby enabling improved heat integration
and avoiding investment in an off-gas compressor. This improved stripper design
maximizes product diesel yield, and is much more energy efficient over conventional
trickle phase hydrodesulfurization (HDS) units, and has demonstrated a reduction
of up to 35% in OPEX (fuel).
Operating conditions depend on the final application. For instance, temperatures
could range between 330°C and 380°C, and pressures between 50 barg and 80 barg
to produce ultra-low-sulfur diesel (< 10 ppms). For vacuum distillates, temperatures
range between 370°C and 420°C, with pressures between 60 barg and 100 barg to
produce a 450-ppmwt hydrotreated distillate as FCC feedstock.
Installation: More than 200 hydrotreater units have been designed and serviced.
Naphtha hydrotreating
• Feedstocks: Straight-run, visbreaker, coker
• Products: Conradsen carbon residue/Isomerization feed quality
(< 0.5 wppm sulfur, < 0.5 wppm nitrogen)
Kerosine hydrotreating
• Feedstocks: Straight-run kerosine
• Products: Jet fuel quality (> 19 mm smoke point)
• Flexible designs: one or two stages, optimized pressure, tailored catalysts
Diesel hydrotreating
• Feedstocks: Straight-run light gas oil, visbreaker LGO, FCC light cycle oil,
coker LGO
• Products: Euro 4/5 (hydrodesulfurization, cetane upgrade, cold-flow
improvement,
density and aromatics)
• Flexible designs: one or two stages, optimized pressure, tailored catalysts
Bulk distillate hydrotreating
• Feedstocks: Wide boiling range straight-run kerosine/LGO
• Products: Jet fuel quality, Euro 4/5
• Flexible designs: 1-stage or 2-stage, optimized pressure, tailored catalysts
Diesel hydrotreating + dewaxing
• Feedstocks: Straight-run LGO, visbreaker LGO, FCC LCO, Coker LGO
• Products: Euro 4/5 cloud point and cold-flow improvement
• Flexible designs: one or two stages, optimized pressure, tailored catalysts,
seasonal operation
VGO hydrotreating (CFHT)
• Feedstocks: Straight-run VGO, coker heavy gasoil, deasphalted oil
• Products: FCC feed (sulfur, nitrogen)
• Flexible designs: Optimized pressure, tailored catalysts
Supplier: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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COMPANY INDEX
Hydroprocessing—Hyvahl™
Application: Upgrade and/or convert atmospheric and vacuum residues, as well as
difficult feedstocks such as deasphalted oil (DAO) and FCC slurry oil, using the Hyvahl
fixed-bed process.
Products: Low-sulfur fuels (0.3% to 1.0% sulfur) and RFCC feeds (removal of metals,
sulfur and nitrogen (N2 ), reduction of carbon residue).
Description: Heavy feedstock and hydrogen (H2 ) are processed in fixed-bed reactors,
typically comprising of a guard reactor section (PRS) and main demetallization (HDM)
and desulfurization (HDS) reactors.
The guard reactors are onstream at the same time in series, and they protect
downstream reactors by removing or converting sediment, metals and asphaltenes
that deactivate or plug the catalyst beds. High pressure and relatively high
temperatures are necessary for the reactions to take place. For difficult feedstocks,
the PRS technology allows the refiner change out catalyst in one reactor “on the fly”
without disturbing the operation.
The guard reactor system can be designed in three alternative configurations:
• Bypassable guard reactor: The first reactor is installed with a bypass, allowing
the operator to take it out of service in case pressure drop issues arise.
• PRS1R: The first reactor can be bypassed, put out of service, re-loaded with
fresh catalyst and placed back into service while the rest of the unit is running.
• PRS2R: The first two reactors are operating in a lead/lag arrangement. At any
moment during the cycle, the lead guard reactor can be put offline, reloaded
with fresh catalyst, and put back onstream in lag position.
Following the guard reactors, the HDM section carries out the remaining
demetallization and asphaltene conversion functions. With most of the contaminants
removed, the residue is treated in the HDS reactors, where the impurities levels are
further reduced to the design specification.
The PRS technology associated with the high stability of the HDS catalytic
system leads to cycle runs exceeding a year, even when processing difficult feedstock
to produce ultra-low-sulfur fuel oil.
Yields: Typical HDS and HDM rates are above 90%, with 30%–50% conversion
of the 565°C+ fraction into distillates.
Installations: In addition to five units in operation, nine more were licensed for a total
capacity exceeding 580,000 bpsd. Four units will be operating on AR and VR feed,
Feed
By-passable
By-pass
HDM-HDS
reaction
section
Product
Re-loadable
PRS2R
HDM-HDS
reaction
section
Product
Feed
Permutable
PRS2R
HDM-HDS
reaction
section
Product
Continued 
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Hydroprocessing—Hyvahl™ (cont.)
seven on 100% AR, one on 100% VR, one on 100% DAO and one on 100% slurry oil.
References:
1. Schwalje, D. and E. Peer, “Hydroprocessing and hydrocracking DAO—
Achieving unlimited cycle lengths with the most difficult feedstocks,”
2017 AFPM Annual Meeting, San Antonio, Texas, 2017.
2. Plain, C., D. Guillaume and E. Benazzi, “Residue desulphurization and conversion,”
Petroleum Technology Quarterly, Summer 2006.
3. Plain, C., D. Guillaume and E. Benazzi, “Better margins with cheaper crudes,”
ERTC 2005 Show Daily.
Licensor: Axens
Website: www.axens.net/product/technology-licensing/10091/hyvahl
Contact: www.axens.net/contact.html
2017 REFINING PROCESSES HANDBOOK
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Hydroprocessing—ISOFINISHING®
Application: Deeply saturate single- and multiple-ring aromatics in base-oil
feedstocks. The product will have very low-aromatics content, very high-oxidation
stability and high thermal stability.
Description: ISOFINISHING catalysts hydrogenate aromatics at relatively low reaction
temperatures. They are especially effective in complete polyaromatics saturation—
a reaction that is normally equilibrium limited. Typical feedstocks are the effluent
from a dewaxing reactor, effluent from hydrated feeds or solvent-dewaxed feedstocks.
The products are highly stabilized base-oil, technical-grade white oil or food-grade
white oil.
As shown in the simplified flow diagram, feedstocks are mixed with recycle
hydrogen (H2 ) and fresh makeup H2, heated and charged to a reactor containing
ISOFINISHING catalyst (1). Effluent from the finishing reactor is flashed in highpressure and low-pressure separators (2, 3). A small amount of light products
are recovered in a fractionation system (4).
Yields: For a typical feedstock, such as dewaxing reactor effluent, the yield can be
> 99%. The chemical-H2 consumption is usually very low, less than ~10 Nm3/m3 oil.
Makeup hydrogen
Process gas
1
Light ends
2
Fresh dewaxed
feed
4
3
Base oil product
Economics:
Investment: For a stand-alone ISOFINISHING unit, the ISBL capital is about
$3,500/bpsd–$5,700/bpsd, depending on the pressure level and size.
Utilities: Typical per bbl feed:
Power, kW
2.6
Fuel, kcal
4.0 x 103
Installations: More than 40 units are in various stages of operation, construction
and design.
References:
1. Meyers, R. A., “Handbook of Petroleum Refining Processes,” 4th Ed.,
McGraw-Hill, 2016.
Licensor: Chevron Lummus Global LLC
Website: www.chevronlummus.com
Contact: SBhattacharya@chevron.com
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2017 REFINING PROCESSES HANDBOOK
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Hydroprocessing—IsoTherming®
Technology
Application: The IsoTherming process provides refiners an economical means to
produce ultra-low-sulfur diesel (ULSD), low-sulfur and low-nitrogen feedstocks to FCC,
and other very low-sulfur hydrocarbon products. The IsoTherming technology
is suitable for both grassroots units and revamps of existing trickle-bed units.
Makeup H2
ULSD product
M
Stripper offgas
Blended feed
Description: The IsoTherming hydroprocessing technology delivers the necessary
hydrogen (H2 ) using a liquid stream rather than a recycle gas system. This eliminates
problems associated with flow mal-distribution, gas-liquid mass transfer, and catalyst
wetting that are typically experienced in a conventional trickle-bed scheme. It also
eliminates the need for the large H2 recycle compressor and some high-pressure
equipment required in conventional hydrotreating.
The technology can be installed as a pre-treat unit upstream of an existing
hydrotreater reactor, or as a new stand-alone process unit. Fresh feed, after heat
exchange, is combined with H2 . To satisfy H2 requirements within the reactor,
additional H2 can be added by means of a liquid recycle stream or inter-bed H2
injection. Operating the reactor liquid-full also acts as a heat sink for the exothermic
reactions. Thus, the reactor operates closer to isothermal conditions, which minimizes
uncontrolled cracking reactions and increases diesel yields.
Operating conditions: Key operating parameters include reactor temperature
and pressure, liquid hourly space velocity, and recycle ratio.
Advantages: Key advantages of the IsoTherming technology include:
• Lower CAPEX and OPEX
• Reduced startup/shutdown times
• Quicker recovery from process upsets
• Reduced light-ends make
• Longer catalyst life
Investment: The IsoTherming technology has demonstrated operating cost
advantages in excess of 30%, and capital cost savings compared to conventional
technology. For revamps where product quality upgrades and capacity increases
are the focus, payback periods could be 12 months or less, depending on the
unit-specific requirements. In addition to lower CAPEX and OPEX for grass roots units,
revamp opportunities present a significant advantage over conventional technology
when product upgrade and capacity increases are the focus.
Naphthaa product
Steam
Utilities: Eliminating the recycle gas loop, in addition to the liquid recycle design,
helps the IsoTherming technology achieve a 40%–60% utility savings over
trickle-bed technology.
Installations: DuPont has 24 licensed IsoTherming units:
20 are grassroots units, while four are revamps of trickle-bed units.
Licensor: DuPont Clean Technologies.
Website: www.dupont.com/products-and-services/clean-technologies/products/
isotherming-hydroprocessing.html
Contact: bioscience.dupont.com/clean-technologies-contact
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Hydroprocessing—ISOTREATING®
Makeup H2 gas
HP purge gas
Application: Hydrotreating of light and middle distillates and various gasoils,
including cracked feedstocks (coker naphtha, coker LGO and HGO, visbreaker gasoil
and LCO) using the ISOTREATING process for deep desulfurization, denitrification
and aromatics saturation, and to produce low-sulfur naphtha, jet fuel, ultra-low sulfur
diesel (ULSD) or improved-quality FCC feed.
Description: Feedstock is mixed with hydrogen (H2 )-rich treat gas, heated and
reacted over high-activity hydrogenation catalyst (1). Several CoMo and NiMo catalysts
are available for use in the ISOTREATING process. One or multiple beds of catalyst(s),
together with Chevron Lummus Global’s advanced high-efficiency reactor internals for
reactant distribution and interbed quenching, are used.
Reactor effluent is cooled and flashed (2), producing H2 -rich recycle gas that,
after hydrogen sulfide (H2 S) removal by amine (3), is partially used as quench gas,
while the rest is combined with makeup H2 gas to form the required treat gas. An
intermediate pressure level flash (4) can be used to recover some additional H2 -rich
gas from the liquid effluent prior to the flashed liquids being stripped or fractionated
(5) to remove light ends, H2 S and naphtha-boiling range material, and/or to
fractionate the higher boiling range materials into separate products.
Operating conditions: Typical reactor operating conditions can range from
600 psig–2,300 psig, 500°F–780°F, 350 psia–2,000 psia H2 partial pressure, and
0.6 hr–1 –3 hr–1 LHSV, all depending on feedstock(s) and product quality objective(s).
Yields: Depends on feedstock(s) characteristics and product requirements.
Desired product recovery is maximized based on required flashpoint and/or specific
fractionation specification. Reactor liquid product (350°F plus TBP material) is
maximized through efficient hydrogenation with minimum lighter liquid product
and gas production. Reactor liquid product (350°F+) yield can vary between 98 vol%
from straight-run gasoil feed to > 104 vol% from predominantly cracked feedstock,
to produce ULSD (< 10 wppm sulfur). Chemical-H2 consumption ranges from
450 scf/bbl–900+ scf/bbl feed.
Advantages: ISOTREATING technology employs high-activity hydrotreating catalyst
resulting in small reactors, high-quality product and long run length, with minimal
byproduct formation. The design incorporates innovative technology, minimizing
emissions and waste effluent.
Economics: Investment varies depending on feedstock characteristics and product
requirements. For a 40,000 bpsd–45,000 bpsd unit for ULSD, the ISBL investment
cost (US Gulf Coast, 2010) is $3,000/bpsd–$3,500/bspd.
Lean amine
3
Wash
water
1
A
A
B
2
Feed
Light ends
and naphtha
Rich amine
2
H2 and
light ends
4
5
B
Product
4
Sour water
Stripping
steam
Investment: Investment cost for ISBL distillate hydrotreating unit is
approximately $3,000/bpsd–$3,500/bpsd.
Utilities: Per 1,000 bbl of feedstock:
Electricity, kWh
1,394
Steam (150 psig), lb
16,000
C.W. rise (10°F), gal
1,635
Fuel (absorbed), Btu
8,370,000
Development/Delivery: The complexity of today’s refineries is such that the
hydrotreating units are fed with blends of SR components, LCO and LCGO.
CLG is continuously developing new generations of ISOTREATING catalyst
and high-performance reactor internals.
Installations: More than 60 units are operating based on ISOTREATING technology,
and an additional 12 units are in various stages of engineering.
Licensor: Chevron Lummus Global LLC
Website: www.chevronlummus.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—MIDW™ technology
Application: High yields of high-quality, low-cloud point diesel.
Description: ExxonMobil’s MIDW technology provides a proven process that
provides high yields of low-cloud point diesel. The process retains paraffins in
the diesel fraction as iso-paraffins, which enhances cetane and volume swell,
as compared with older technologies that rely on cracking. This process results
in a much higher diesel yield, particularly for deep reductions in cloud point.
Advantages: Advantages of MIDW include:
• Higher performance
° Better low-temperature properties
° Increased unit flexibility
• High yields: paraffins are isomerized instead of cracked
• Flexible process configurations
° Drop-in catalyst solutions to existing hydrotreaters
° Low capital expenditures
° Sweet configurations
° Sour configurations
• Reliable and robust operation
° Multiple generations for a variety of applications.
References:
1. K. Peretti, K., and J. Locke, “MIDW technology as a drop-in catalyst solution:
Benefits of upgrading to a highly isomerization-selective distillate dewaxing
catalyst,” AFPM Annual Meeting, San Antonio, Texas, March 2017.
Installations: Typically, MIDW services include consultation from design through the
startup phases of project implementation and beyond.
Licensor: ExxonMobil Catalysts & Licensing LLC.
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—OCR and UFR
with RDS/VRDS
Application: Hydrotreat atmospheric residuum (AR) and vacuum residuum (VR)
feedstocks to reduce sulfur, metals, nitrogen, carbon residue and asphaltene contents.
The process converts residuum into lighter products, while improving the quality
of unconverted bottoms for more economic downstream use.
Description: Oil feed and hydrogen (H2 ) are charged to the reactors in a oncethrough operation. The catalyst combination can be varied significantly according to
feedstock properties to meet required product qualities. Product separation is done
by the hot separator, cold separator and fractionator. Recycle H2 passes through
a hydrogen sulfide (H2 S) absorber.
A wide range of AR, VR and deasphalted oil (DAO) feedstocks can be processed.
Existing units have processed feedstocks with viscosities as high as 6,000 cSt
at 100°C and feed-metals contents of 500 ppm.
Onstream catalyst replacement (OCR) reactor technology has been
commercialized to improve catalyst utilization and increase run length with highmetals, heavy feedstocks. This technology allows spent catalyst to be removed from
one or more reactors and replaced with fresh catalyst while the reactors continue to
operate normally. The novel use of up-flow reactors in OCR provides greatly increased
tolerance of feed solids, while maintaining low-pressure drop.
A related technology called an up-flow reactor (UFR) uses a multi-bed, up-flow
reactor for minimum pressure drop in cases where onstream catalyst replacement is
not necessary. OCR and UFR are particularly well suited to revamp existing RDS/VRDS
units for additional throughput or heavier feedstock.
Operating conditions:
Reactor temperatures, °F
Reactor pressure, psig
LHSV
Yields: For Arabian Heavy, 650°F+ AR:
Feed
Gravity, API
Sulfur, wt%
Nitrogen, wt%
Carbon residue, wt%
Nitrogen, wt%
Ni+V, ppmw
675–760
2,400–3,000
0.12–0.35
11.8
4.37
0.30
13.6
0.30
131
To new HX
Makeup H2
To gas recovery
New UFR + FB reactors
From new HX
Cold HP
separator
H2O
Unstabilized
naphtha
H2S
Recycle gas
scrubbing
Product
stripper
Steam
Product
Sour water
Fresh feed
Filter
Products, wt%
C4–
C5 – 280°F
280°F–650°F
650°F+
New HX
Hot HP
separator
LP
separator
0.23
1.38
12.51
82.81
Advantages: Minimized downstream equipment fouling, commercially proven,
extremely reliable, product suitable for RFCC feed or LSFO.
Installations: CLG has a list of 46 reference sites that can be made available
upon request.
Continued 
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—OCR and UFR with RDS/VRDS (cont.)
References:
1. Frumkin, H. A. and G. D. Gould, “Isomax takes sulfur out of fuel oil,” AIChE
Meeting, New Orleans, Louisiana, March 16–20, 1969.
2. Bridge, A. G., E. M. Reed, P. W. Tamm and D. R. Cash, “Chevron Isomax process
desulfurizes Arabian Heavy residue,” 74th National AIChE Meeting, New Orleans,
Lousisiana, March 11–15, 1973.
3. Bridge, A. G., G. D. Gould and J. F. Berkman, “Residue process proven,” Oil and
Gas Journal, January 1981.
4. Saito, K., Shinuzym, F. Fukui and H. Hashimoto, “Experience in operating highconversion residual HDS process,” AIChe Meeting, San Francisco, California,
November 1984.
5. Rush J. B. and P. V. Steed, “Refinery experience with hydroprocessing resid for
FCC feed,” 49th Midyear Refinery Meeting, American Petroleum Institute (API),
New Orleans, Louisiana, May 16, 1984.
6. Reynolds, B. E., D. V. Law and J. R. Wilson, “Chevron’s Pascagoula residuum
hydrotreater demonstrates versatility,” NPRA Annual Meeting, San Antonio, Texas,
March 24–26, 1985.
7. Speight, J. G., The Chemistry and Technology of Petroleum, 2nd Ed., Marcel
Dekker, New York, 1991.
8. Kanazawa H. and B. E. Reynolds, “NPRC’s success with Chevron VRDS,” NPRA
Annual Meeting, San Antonio, Texas, March 25–27, 1984.
9. Kaparakos, N. E., J. S. Lasher, S. Sato and N. Seno, “Nippon Mining Company
upgrades vacuum tower bottoms in Gulf resid HDS unit,” Japan Petroleum
Refining Conference, Tokyo, Japan, October 1984.
10. Hung, C., H. C. Olbrich, R. L. Howell and J. V. Heyse, “Chevron’s new HDM catalyst
system for a deasphalted oil hydrocracker,” AIChE 1986 Spring National Meeting,
Paper No. 12b, April 10, 1986.
11. Reynolds, B. E., D. R. Johnson, J. S. Lasher and C. Hung, “Heavy oil upgrading for
the future: The new Chevron hydrotreating process increasesflexibility,” NPRA
Annual Meeting, San Francisco, California, March 19–21, 1989.
12. Reynolds, B. E. and M. A. Silverman, “VRDS/RFCC provides efficient conversion
of vacuum bottoms into gasoline,” Japan Petroleum Institute Petroleum Refining
Conference, Tokyo, Japan, October 18–19, 1990.
13. Reynolds, B. E. and D. N. Brossard, “RDS/VRDS hydrotreating broadens
application of RFCC,” ATI Quarterly, Winter 1995/1996.
Licensor: Chevron Lummus Global LLC.
Website: www.chevronlummus.com
Contact: robertwade@chevron.com
2017 REFINING PROCESSES HANDBOOK
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Hydroprocessing—Prime-D™
Application: Ultra-low sulfur diesel (ULSD) production or cetane/density
improvement (conventional Prime-D), cold flow properties improvement
(Prime-D with dewaxing) or ultimate density/cetane improvement or gasoline
production (Prime-D with cracking). Axens offers flexible and customized
process schemes depending on the production target.
Feedstocks: Prime-D performance technology has been proven in terms of feedstock
flexibility and its ability to treat a wide range of middle distillates feeds: straight runs
diesel; difficult feeds (particularly when cetane and density improvement is required)
such as light cycle oil (LCO) from FCCUs or coker gasoil (CGO) from coker units
containing high contents of olefin and aromatics, or even hydro-processed derived
gasoil coming from mild hydrocracking (MHC); and Hyvahl units containing
very refractory sulfur species.
Description: In the basic process of conventional Prime-D, as shown in the diagram,
feed and hydrogen (H2 ) are preheated in a feed-reactor effluent exchanger (1) and
brought to reaction temperature in the furnace (2) before entering the reactor (3).
The reaction effluent is cooled down in exchangers (1) and an air cooler (4) before
being separated in three phases (liquid, vapor and water phases) in the separator
(5). The H2-rich gas phase is treated in an amine absorber for hydrogen sulfide (H2 S)
removal (if required) (6) and compressed before being split into two streams: one
stream is sent as quench gas between the catalytic bed to control the exotherm of the
reaction (if required), while the other stream is mixed with H2 makeup and injected
with fresh feed. The liquid phase is sent to a stripper (7), where small amounts of
gas and naphtha are removed and high-quality product diesel is recovered at bottom.
Advantages: Axens Prime-D toolbox offers the latest high-performance technologies,
catalysts and services for grassroots or revamps, including the selection of the proper
combination of Axens catalyst for hydrotreatment, depending on the unit target:
• Ace™ Series (HR 626, HR 648,…) offering outstanding stability
• Latest ImpulseTM Series (HR 1246, HR 1248, HR 1218,…) designed for high activity,
maximized by improving active phase dispersion, wide increase
in active sites
• CoMo-type catalysts for maximum hydrodesulphurization at low
to medium pressures
• NiMo-type catalysts for maximum hydrodesulphurization
and hydrodearomatisation at higher pressures.
Off-gas
2
3
7
4
1
Ultra-low-sulfur
product
5
6
Feed
Makeup H2
H2 recycle
Amine
absorber
H2S
Additional dewaxing catalysts for cold-flow properties improvement, or cracking
catalysts, could also be used for ultimate density and cetane improvement or gasoline
production:
• Grading: ACT Series for efficient catalyst protection and reactor pressure drop
control
• Catapac™ for optimum dense and homogeneous loading of the catalyst bed
• EquiFlow® reactor internals: EquiFlow Hy-Tray™ distributor trays for near
perfect gas/liquid distribution throughout the catalytic bed underneath;
and EquiFlow Hy-Quench-XM™ Quench box for reaction exotherm control,
ensuring compact installation with high thermal efficiency
• Advanced process control APC systems for dependable operation
and longer catalyst life
• Sound engineering design based on R&D, process design and technical
service feedback to ensure the right application of the right technology,
for new and revamp projects.
Continued 
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Hydroprocessing—Prime-D™ (cont.)
Whatever the unit target—ULSD, high cetane or low aromatics, cold-flow
properties improvement or gasoline production— Prime-D’s Hydrotreating
Toolbox approach is cost-effective.
Installations: More than 250 middle distillate hydrotreaters have been licensed
or revamped.
References:
1. “Premium performance hydrotreating with Axens HR 400 Series hydrotreating
catalysts,” NPRA Annual Meeting, San Antonio, Texas, March 2002.
2. “The hydrotreating toolbox approach,” Hart’s European Fuel News, May 29, 2002.
3. “Squeezing the most from hydrotreaters,” Hydrocarbon Asia, April/May 2004.
4. “Upgrade hydrocracked resid through integrated hydrotreating,” Hydrocarbon
Processing, September 2008.
Licensor: Axens
Website: www.axens.net/product/technology-licensing/10031/prime-d.html
Contact: www.axens.net/contact.html
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Hydroprocessing—
SCANfining™ technology
Recycle gas
compressor
Makeup gas
Application: A higher octane approach to ultra-low-sulfur gasoline (ULSG) technology.
Description: SCANfining technology offers a cost-effective solution for meeting
the low-sulfur requirements of gasoline. The technology removes sulfur, with low
octane loss, by utilizing a jointly developed ExxonMobil and Albemarle catalyst
technology coupled with ExxonMobil’s hydroprocessing design. With more than
40 licensed units in operation, ExxonMobil brings demonstrated industry experience in
offering customizable solutions to meet today’s refining challenges.
Advantages: SCANfining technology benefits include:
• ExxonMobil’s experience in inventing, designing and operating the technology
• Lower hydrogen (H2 ) consumption
• Meets ULSG (10 ppm sulfur) at low octane loss
• Customized solutions engineered to a variety of configurations
• 43 working units with SCANfining technology deployed worldwide
• More than 1.3 MMbpd capacity.
Purge
Preheater
Preheater
Cooler
Feed
Amine
scrubber
Light ends
HDS
reactor
Pretreat
reactor
Separator
Product
stripper
Low-sulfur naphtha
Installations: Typically, SCANfining services include consultation from design through
the startup phases of project implementation and beyond.
Licensor: ExxonMobil Catalysts & Licensing LLC
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Hydroprocessing—SLHT
Application: SINOPEC’s continuous liquid-phase hydrotreating technology (SLHT)
is used to deeply desulfurize straight-run diesel feedstocks or diesel blended with a
small amount of cracked materials. This process produces low-sulfur or ultra-low sulfur
diesel products.
Description: In the SLHT process, the hydrogen (H2 ) required for the reactions is
dissolved in the mixture of the fresh feed and partially-recycled oil. The feed mixture,
with dissolved H2 , is sent to the reactor where the liquid is in continuous phase, while
the small amount of extra-added excess H2 gas is in dispersed phase.
Advantages: The advances of the SINOPEC SLHT process include:
• Since there is no circulation of recycled gas, the recycle H2 compressor
is eliminated. This results in a lower operating cost. The energy consumption
can be reduced by more than 20% compared to that of a conventional
hydroprocessing unit.
• As a carrier of fresh H2 into the reactor, the recycled oil can increase the
H2 content of the reactor. While acting as a heat sink that removes heat from
the reactor, it can lower catalyst bed temperature rise and avoid hot spots,
prolonging catalyst life, reducing yields of light gas and increasing diesel yield.
• The excess H2 gas in dispersed phase can ensure the required H2 concentration
for the reactions, reducing energy consumption and the amount of recycled oil.
• Under typical operating conditions, the sulfur content of the diesel product
is lower than 10 wppm.
• The cycle length of fresh catalyst is 3 years. The regenerated catalyst can be
used, and the total catalyst service life can be up to 9 years.
• The operating flexibility of this process unit is 60 to 110%.
Licensor: China Petrochemical Technology Co. Ltd.
Website: sinopectech.com
Contact: g-technology@sinopec.com; +86-10-6916 6661
Installations: SLHT technology has been applied in five units. The largest single unit
has a capacity of 2.6 MMtpy.
References:
1. Dong, X., “First commissioning of a 2.2-MMtpy continuous liquid-phase diesel
hydrotreating unit,” Petroleum Refinery Engineering, 2014.
2. Dong, X., “Advantage of continuous liquid phase diesel hydrogenation in energy
consumption,” Petroleum Processing & Petrochemicals, 2015.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Internals—Adsorbents
Application: Wide spectrum of applications across industries such as refining,
petrochemical, chemical and gas processing. The BASF Adsorbents portfolio includes
proprietary activated alumina, alumino-silica gels (Sorbead®), noble metals, and base
metal oxide guard bed media, including the PuriStar® family of media.
Description: Adsorbents used are typically in the form of spheres, tablets, extrudate
or monoliths with hydrodynamic diameters between 0.5 mm and 10 mm.
Advantages: High abrasion resistance, high thermal stability and small pore
diameters, which results in higher exposed surface area and high surface capacity
for adsorption. The adsorbents also have a distinct pore structure that enables
fast transport of targeted molecules.
Development/Delivery: Adsorbent Technologies:
• Activated alumina adsorbents
• Alumina silica gel Sorbead adsorbents
• Catalyst substrates and intermediates
• Metal oxide adsorbents
• Molecular sieve adsorbents.
Installations: BASF Adsorbents have been used globally by hundreds of customers
for various applications.
Licensor: BASF
Website: www.catalysts.basf.com/adsorbents
Contact:
Americas: +1-732-205-5000 +1-800-889-9845
Email: catalysts-americas@basf.com
Asia Pacific: +86-21-2039-3066
Email: catalysts-asia@basf.com
Europe, Middle East, Africa: +31-30-666-9555
Email: catalysts-europe@basf.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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Internals—Hydroprocessing Reactor
Application: Any hydroprocessing reactor, regardless of feed and product
specifications.
Description: A specialized portfolio of hydroprocessing reactor internals designed
to maximize functionality, accessibility, safety and time saving (F.A.S.T.TM ).
The functionality features ensure achieving the targeted performances
(i.e., distribution, mixing, particulate removal) over a broad operating range
and over the whole duration of the cycle length. Accessibility simplifies maintenance
operations and promotes more ergonomic working conditions for the workers inside
the reactor. Safety is the result of improved accessibility and of shortening the time
that workers use in confined spaces. Time savings increases reactor availability.
Operating conditions: No restrictions to the design of Topsoe F.A.S.T. equipment.
Advantages: F.A.S.T. internals maximize volume and catalyst utilization, safety
and reactor availability. In turn, this converts in better product quality and/or longer
cycle length and/or possibility to treat more severe feeds and higher availability.
Investment: The improvement in availability typically pays the investment back
within the first year of operation.
Installations: As of early 2017, there over 1,000 pieces of main equipment (distribution
trays, mixers and scale catchers) operating in roughly 450 individual units.
References:
1. Zahirovic E. and Bendtsen P.: Digital Refining, December 2016
Licensor: Haldor Topsoe, Refinery Business Unit
Website: www.topsoe.com/products/equipment
Contact: roc@topsoe.com
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Internals—ISOMIX-e®
Application: ISOMIX-e offers:
• Maximum catalyst utilization: Data and simulations show a 15°F (8°C) activity
advantage with state-of-the-art reactor internals, resulting in an increase
in run length or unit throughput.
• Safe operations: The ease of temperature management is enhanced.
When paired with proper catalyst selection and loading, the resulting uniform
temperature distribution and mitigation of hot spots in the reactor serves
to increase catalyst life, run length and operability.
• Easier maintenance: The use of wedge pin closures in ISOMIX-e reactor internals
eases maintenance and provides optimum unit operating flexibility for faster
installation, turnarounds and retrofits.
Advantages: ISOMIX-e state of the art internals offer an innovative yet easily
maintainable compact design, utilizing upturned catalyst support beams and tray
trusses, a compact mixing box and quench ring, and a tight nozzle spray pattern.
The compact design allows additional catalyst volume or reduced reactor size.
ISOMIX-e internals offer benefits to reactor performance. Improved distribution,
quenching and mixing result in:
• Increased temperature spreads across the catalyst beds
• Better catalyst activity and improved cycle length (or increased throughput)
500
Cumulative CLG reactor designs
400
300
200
100
0
1960
1962
1964
1966
1968
1970
1972
1974
1976
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
Cumulative reactor designs
Description: ISOMIX-e top tray reactor internals use several advanced design features,
including an inlet distribution basket and a top nozzle tray assembly, which promote
ease of maintenance and facilitate optimum catalyst loading. Wedge pins at screen
splices provide quick access through uncluttered manways, and also facilitate the
quick installation and removal of the screen and grid panels.
Similarly, ISOMIX-e interbed reactor internals use several advanced design features
that promote easy maintenance and excellent performance. Interbed reactor internals
employ wedge pin connectors throughout, include a two-piece, lightweight mixing box.
The top nozzle tray and the inter-bed nozzle tray utilize ISOMIX-e nozzles, which
offer a high degree of uniform distribution over a wide range of gas and liquid rates.
The nozzle design allows the trays to have a high tolerance to out-of-levelness.
As with top tray reactor internals, the catalyst support grid is supported by
upward-oriented support beams with tapered ends. Thinner tray plates are used
without the need for additional support hanger brackets or rods.
CLG’s reactor internals also include a low-profile outlet collector. The interbed
reactor internals and the outlet collector independently allow an increase in
catalyst volume.
600
Year
•
•
•
•
•
A reduction in start-of-run temperatures
Lower catalyst fouling rates
Improved product yield structure
Improved turndown ratios
Reduction in maintenance/installation turnaround time (an average of 4 hr for
removal and installation per reactor).
Development/Delivery: CLG’s reactor internals development is an ongoing process
led by its engineers and scientists. The company is now on the 8th generation of
internals design with ISOMIX-e. CLG’s reactor internals development began in the
1960s with the advent of modern hydrocracking.
Continued 
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2017 REFINING PROCESSES HANDBOOK
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Internals—ISOMIX-e® (cont.)
Grass Roots Installations: ISOMIX-e has achieved radial differential temperatures
as low as 2°F at inlet and 10°F at outlet, despite significant exotherms in multiple beds.
Retrofit Installations: CLG offers retrofitting solutions for existing fixed-bed
reactors to help address issues of poor run lengths/under-utilization of catalyst,
high temperature spreads, hot spots/coke formations, aging internals, poor turndown
ratios, high turnaround durations or the need for higher throughputs.
References:
1. Meyers, R. A., Handbook of Petroleum Refining Processes, 4th Ed.,
McGraw-Hill, 2016.
Licensor: Chevron Lummus Global LLC
Website: www.cbi.com/CLG/Reactor-Internals/ISOMIX-e
Contact: Rajan.Jawale@chevron.com
2017 REFINING PROCESSES HANDBOOK
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Internals—Process Catalysts
Application: Full-range heterogeneous catalyst portfolio:
• Base metal catalysts
• Precious metal catalysts
• Zeolites and solid acid catalysts
• Washcoated catalysts on honeycombs and metal substrates
• Skeletal metal catalysts (Actimet™)
Description: Our global catalyst R & D and catalyst technical service staff provide
immediate, local attention to customer catalyst needs. We offer precious metals
supply and full-loop management services, including refining to recover precious
metals from spent catalysts. We are committed to working diligently with you to
understand your catalyst needs and translate them into the right catalyst for your
process. We begin by working with you to determine the right catalyst solution
for your applications. This may range from an off-the-shelf chemical catalyst to
a proprietary catalyst tailored for your application, or even a joint development
program undertaken with you to develop a catalyst unique to your needs and
exclusive to your use. Finally, we offer custom catalyst manufacturing services,
freeing you to focus on your core business.
Advantages: Leading manufacturer of catalysts in the chemicals industry:
• Catalyst solutions along the chemical value chain ranging from oxidation,
intermediates production to specialty applications, such as pharmaceutical
and fine chemicals
• Technology catalysts and process licensing in chemical processes
(e.g., hydrogenation in steam cracker and refineries)
• In-depth knowledge and expertise in chemical markets, catalysts
and processes provide optimized results for your business.
Licensor: BASF
Website: www.catalysts.basf.com/chemicals
Contact:
Americas: +1-732-205-5000 +1-800-889-9845
Email: catalysts-americas@basf.com
Asia Pacific: +86-21-2039-3066
Email: catalysts-asia@basf.com
Europe, Middle East, Africa: +31-30-666-9555
Email: catalysts-europe@basf.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Internals—Reactor internals
Application: Shell reactor internals provide opportunities to generate additional
margins for processes featuring fixed-bed catalytic reactors. Customized solutions
are offered for:
• Tackling catalyst bed fouling
• Maximizing catalyst volume uptake in reactors and catalyst utilization
• Virtually eliminating radial temperature maldistribution
• Reducing turnaround times by several days
• Enhancing safety during reactor maintenance and enabling
much quicker egress.
Description: Shell reactor internals can help to reduce catalyst bed fouling
significantly and minimize interbed height and/or enable catalyst beds to be
combined to maximize bed volumes. Optimal liquid–gas distribution combined with
ultra-uniform radial temperature distribution and high-performance quenching can
help to maximize catalyst utilization, lower weighted-average bed temperatures
and increase run length. The Shell reactor internals are designed for safe, easy
maintenance, thereby minimizing turnaround times and improving plant availability.
Shell Global Solutions offers a wide range of reactor internals, including
• Shell filter trays, scale-catching trays and gas-phase settling trays,
which offer customized designs to trap large and small particles and
significantly delay catalyst bed fouling.
• Shell high dispersion (HD2) trays, low-gas HD trays and liquid-even
distribution trays, which offer near-perfect liquid–gas distribution over
catalyst beds for maximum catalyst volume utilization.
• Shell Ultra Flat Quench (UFQ) internals provide perfect liquid–gas mixing
and quenching to minimize radial temperature maldistribution.
Operating conditions: All Shell reactor internals are designed to offer
100% performance from turndown to design conditions (50%–120% of a unit’s
design feed rate).
Yields: NA
Advantages:
• Increased catalyst volumes: up to 30%
• Increased catalyst utilization: up to 200%
• Longer cycle length, up to 300%, owing to lower catalyst deactivation
and little to no fouling
• Improved safety and reduced turnaround times thanks to boltless
and weldless installation
• Wide range of operation and robust design
• Wide range of applications (100% gas, two-phase flow and 100% liquid).
Investment: With their high return on investment (on average, less than 1 yr), Shell
reactor internals are a good retrofit option for any unit to help maximize profit for
minimum capital expenditure.
Continued 
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2017 REFINING PROCESSES HANDBOOK
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Internals—Reactor internals (cont.)
Development: Shell reactor internals’ designs are the result of extensive studies and
tests performed at Shell Technology Centre Amsterdam, the Netherlands.
Delivery: Lead times depend on the number of beds and the complexity of the
revamp. A typical delivery time is 42 weeks (shorter delivery times can be discussed).
Installations: More than 1,600 reactors revamped in 550 units worldwide.
References:
• SASREF hydrocracker revamp: Installing Shell reactor internals in combination
with catalyst beds enabled a capacity increase for the unit, higher selectivity
toward middle distillates and increased cycle length.
• Shell Martinez catalytic feed hydrotreater: Installing filter trays on top of the
reactors to trap iron sulfide particles enabled a 300% increase in cycle length.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
2017 REFINING PROCESSES HANDBOOK
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Internals—Selective Catalytic
Reduction
Application: Selective catalytic reduction (SCR) catalysts to control NOx emissions
Description: NOx off-gas is produced in the FCC process, during the use of steam
boilers, process furnaces and process heaters, and by compressor engines. All NOx
sources are regulated and must be reduced using emissions control technology. BASF
SCR catalysts are homogeneous, honeycomb catalysts that are robust and reliable.
Advantages: The long lifetime and regulatory compliance guarantee allows you
to focus on getting the most value out of your refinery, without having to worry
about emissions regulations.
Development/Delivery: BASF services include:
• Basic catalyst design (required catalyst amount)
• Catalyst installed in modules/reactors
• Metal sealing
• Lifting travers for modules
• Test elements in the modules
• Walking grid on top of the modules
• Drawings (modules, traverse, sealing)
• Supervision for catalyst installation
• Analysis of catalyst elements.
Installations: BASF SCR media have been used globally by hundreds of customers for
various applications.
Licensor: BASF
Website: http://www.catalysts.basf.com/p02/USWeb-Internet/catalysts/en/content/
microsites/catalysts/prods-inds/stationary-emissions/about
Contact:
Americas: +1-732-205-6078
Asia Pacific: +86-21-6109 1862
Europe, Middle East, Africa: +49-621-60-59742
Email: sandra.king@basf.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Isomerization—GT-IsomPX℠
Application: GT-IsomPX is GTC’s xylene isomerization technology, and is available
in two versions: EB isomerization and EB dealkylation. Both versions gain high
ethylbenzene (EB) conversion rates while producing equilibrium-mixed xylenes.
Catalysts that exhibit superior physical activity and stability are the key to this
technology. The technology and catalysts are used commercially in several
applications.
Description: For an EB dealkylation type of isomerization, the technology
encompasses two main processing areas: the reactor section and the product
distillation section. In this process, the paraxylene (pX)-depleted feed stream
is first mixed with hydrogen (H2 ). The mixed stream is then heated against
reactor effluent and through a process furnace. The heated mixture is fed into
an isomerization reaction unit, where m-xylene, o-xylene and pX are isomerized
to equilibrium, and EB is de-alkylated to benzene.
The reactor effluent is cooled and flows to the separator, where the H2 -rich
vapor phase is separated from the liquid stream. A small portion of the vapor
phase is purged to control recycle H2 purity. The recycle H2 is then compressed,
mixed with makeup H2 and returned to the reactor.
The liquid stream from the separator is pumped to the xylene column to remove
light hydrocarbons. The liquid stream from the deheptanizer overhead contains
benzene and toluene and is sent to the distillation section to produce high-purity
benzene and toluene products. The side stream from the xylene’s column contains
mixed xylenes and a small amount of C9+ aromatics. This liquid stream is returned to
the pX recovery section.
Advantages:
• pX in xylenes reaches thermodynamic equilibrium after reaction
• With the EB-dealkylation catalyst, the byproduct benzene is produced
at high purity by simple distillation
• Low H2 /HC ratio, high WHSV and low xylenes loss
• Long cycle length
• Efficient heat integration scheme reduces energy consumption
• Turnkey package for high-purity benzene, toluene and PX production available
from licensor.
Makeup H2
Reactor purge gas
Offgas
Light ends
Reactor
Mixed xylenes
Xylene
column
Feed
C9+
C9+ feed (optional)
Installations: Two commercial license
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
Investment: Feedrate: 4 MMtpy (88,000 bpd); erected cost (excluding the xylene
column): $26 MM (ISBL, 2017 US Gulf Coast Basis).
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Isomerization—Ipsorb™ and Hexorb™
Application: Isomerization of C5 /C6 paraffin-rich hydrocarbon streams to produce
high RON and MON products suitable for addition to the gasoline pool.
Description: Several variations of the C5 /C6 isomerization process are available
according to feedstock composition and octane objective. The choice can be a
once-through reaction for an inexpensive (but limited) octane boost; or for substantial
octane improvement and as an alternate (in addition) to the conventional DIH
recycle option or to combination of fractionations (DeIsoPentanizer, DePentanizer,
DeIsoHexanizer). The Ipsorb Isom scheme isshown to recycle the normal paraffins
for their complete conversion. The Hexorb Isom configuration achieves a complete
normal paraffin conversion plus substantial conversion of low-octane (75) methyl
pentanes, providing maximum octane results. With the most active isomerization
catalyst (chlorinated alumina), particularly with the ATIS2L catalyst jointly developed
by Albemarle and Axens, the isomerization performance in terms of RON varies
from 84–92: once-through isomerization (84), isomerization with DIH recycle (88),
Ipsorb (90) and Hexorb (92).
Operating conditions: The Ipsorb isomerization process uses a deisopentanizer (1)
to separate the isopentane from the reactor feed. A small amount of hydrogen (H2 )
is also added to reactor (2) feed. The isomerization reaction proceeds at moderate
temperature, producing an equilibrium mixture of normal and isoparaffins. The
catalyst has a long service life. The reactor products are separated into isomerate
product and normal paraffins in the Ipsorb molecular sieve separation section (3),
which features a novel vapor phase PSA technique. This enables the product to consist
entirely of branched isomers.
CW
Off-gas
C5/C6 feed
1
2
3
Isomerate
H2
Recycle
Licensor: Axens
Website: www.axens.net/product/process-licensing/10024/c5-c6-isomerization.html
Contact: www.axens.net/contact.html
Installations: More than 85 C5 /C6 isomerization licenses have been awarded over
the last 25 yr, with more than 50 obtained in the last 10 yr. More than 30 units are is
operation, including one Ipsorb unit.
References:
1. Axens/Albemarle, “Advanced solutions for paraffin isomerization,” NPRA Annual
Meeting, San Antonio, Texas, March 2004.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Isomerization—Isomalk-2℠
n-pentane recycle
H2 dryer
Compressor
C1-C4 gas
Makeup H2
Deisohexanizer
H/T feed
Depentanizer
Reactor section
Stabilizer
Description: Isomalk-2 is a vapor-phase isomerization technology with benzene
reduction. Light naphtha is hydro-desulfurized and fed to a feed vaporizer, and then
sent to the isomerization reaction section. Normal paraffins are isomerized into
an equilibrium mixture of iso-paraffins to increase the octane value. Any benzene
in the feed is saturated in the first of two reactors. The second reactor completes the
isomerization reaction. Isomalk-2 does not require bone-dry feed or HC feed dryers.
Process feeds include light straight run (LSR), but could also be applied to a reformate
stream, and LSR/reformate combinations hydrocracker naptha, among others.
Product RON 91-92
Isopentane fraction
Deisobutanizer
Application: Isomalk-2 is used to isomerize light naphtha, along with benzene
reduction. It is a low-temperature isomerization technology licensed in partnership
between GTC Technology and NPP NEFTEHIM, which has been commercially proven
in all process configurations to produce isomerate from 80–93 RON. This flexible
process, having a simple process flow, utilizes a robust platinum-based mixed
metal oxide catalyst that works effectively at low temperatures, while delivering
greater stability against the influence of catalyst poisons. Isomalk-2 is a competitive
alternative to the three most commonly used light gasoline isomerization processes:
zeolite, chlorinated alumina and sulfated oxide catalysts. This technology has been
demonstrated in grassroots and revamp units, including revamps of all the previously
mentioned technologies, semi-regenerative reforming units, diesel HDT, among others.
n-hexane recycle
Operating conditions: 120°C–180°C, 30 kg/cm2g–33 kg/cm2g
Yields: 98 wt%+
Advantages:
• All versions are optimized for high conversion rate, while producing a close
approach to thermal equilibrium
• Catalyst exhibits superior physical activity and stability
• Commercially used in all configurations of recycle
• Process capability to produce up to 93 RON with full recycle
• Regenerable catalyst with superior tolerance to process impurities and water
• No chloride addition required, no caustic section
• Operating temperature range of 120°C–180°C
• Mass yield is more than 98%
• Expected cycle length is more than 6 yr; expected catalyst life is more than 12 yr.
• Reduced hydrogen (H2 ) consumption.
Economics: Feedrate: 325 Mtpy (10 Mbpd) for a once-through unit; erected: $15 MM
(ISBL, 2016 US Gulf Coast Basis).
Investment: $1 MM–$2.5 MM/1,000 bpd
Utilities: Overall energy requirement is 0.45 MMKCal/mt of feed–0.65 MMKCal/mt of feed
Installations: 31 units licensed
Licensor: GTC Technology US, LLC
Website: www.gtctech.com
Contact: inquiry@gtctech.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Isomerization—IsomPlus®
Application: Convert normal olefins to isoolefins.
Description:
C4 olefin skeletal isomerization (IsomPlus)
A zeolite-based catalyst especially developed for this process provides near
equilibrium conversion of normal butenes to isobutylene at high selectivity and long
process cycle times. A simple process scheme and moderate process conditions
result in low capital and operating costs. Hydrocarbon feed containing n-butenes,
such as C4 raffinate, can be processed without steam or other diluents, nor with the
addition of catalyst activation agents to promote the reaction. Near-equilibrium
conversion levels up to 44% of the contained n-butenes are achieved at greater
than 90% selectivity to isobutylene.
During the process cycle, coke gradually builds up on the catalyst, reducing
the isomerization activity. At the end of the process cycle, the feed is switched to
a fresh catalyst bed, and the spent catalyst bed is regenerated by oxidizing the
coke with an air/nitrogen mixture. The butene isomerate is suitable for making
high-purity isobutylene product.
C5 olefin skeletal isomerization (IsomPlus)
A zeolite-based catalyst especially developed for this process provides nearequilibrium conversion of normal pentenes to isoamylene at high selectivity and
long process cycle times. Hydrocarbon feeds containing n-pentenes, such as C5
raffinate, are processed in the skeletal isomerization reactor without steam or other
diluents, nor with the addition of catalyst activation agents to promote the reaction.
Near-equilibrium conversion levels up to 72% of the contained normal pentenes
are observed at greater than 95% selectivity to isoamylenes.
Economics: The IsomPlus process offers the advantages of low capital investment and
operating costs coupled with a high yield of isobutylene or isoamylene. Also, the small
quantity of heavy byproducts formed can easily be blended into the gasoline pool.
Capital costs (equipment, labor and detailed engineering) for three different
plant sizes are:
Total installed cost:
Feedrate, bpd
ISBL cost, $MM
5,000
20
10,000
30
20,000
40
2
C4s to MTBE unit
3
4
5
C5+
MTBE unit raffinate
Utility consumption: per barrel of feed (assuming an electric-motor driven
compressor) are:
Power, kWh
3.2
Fuel gas, MMBtu
0.44
Steam, MP, MMBtu
0.002
Water, cooling, MMBtu
0.051
Nitrogen, scf
57–250
Installation: Four plants are in operation. Two licensed units are in various stages
of design.
Licensor: Lummus Technology, a CB&I company
Contact: lummus.tech@CBI.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Isomerization—MAX-ISOM™
Applications: MAX-ISOM technology is a C5 /C6 naphtha isomerization process
for increasing the octane of desulfurized light naphtha to make it suitable for
blending into high-octane gasoline products. Due to the process configuration used,
naphtha containing high concentrations of benzene can be processed directly in the
isomerization step without the normal requirement for an additional reaction stage for
benzene saturation.
MAX-ISOM can also be extended to isomerize C7 light naphtha in a similar fashion
to C5 /C6 light naphtha. This process is an important departure from conventional
processing in a catalytic reformer, as it offers an alternative option for gasoline
blending where tight specifications for the content of aromatics are applied.
The process employs the principles of catalytic distillation. Beds of isomerization
catalyst are installed in a single fractionation column between sections containing
distillation trays. Each bed has the functionality of isomerizing n-pentane, n-hexane
and, where required, n-heptane to the specific isomers. If the option of benzene
saturation is required, this can be accomplished in a separate catalytic section within
the column. Heat generated by the very-exothermic reaction is dissipated into the
column, where it is included in the overall heat balance. Therefore, the process is
untroubled by high concentrations of benzene.
As the process has multiple reaction zones, optimized feed points can be used
for systems with multiple feeds of varying compositions. It is preferred that the feed
is desulfurized and dried, but the catalyst can tolerate up to 10 ppmw sulfur and 20
ppmv moisture. A standard C5 /C6 feed can also have an endpoint up to 100°C.
Description: The liquid hydrocarbon feed is pumped to system pressure and,
depending on the source and quality of the feed stream, an adsorption dryer may
be used to reduce the moisture content of the feed to the required specification of
less than 20 ppm (vol) moisture. The feed stream is then heated to the column feed
temperature using feed effluent heat exchange.
The MAX-ISOM column is a catalytic distillation column consisting of separate
reaction zones and fractionation zones. The number of reaction zones can vary
depending on feed and product requirements, but a minimum of two reaction zones
within the column maximize conversion of C5 /C6 paraffins to high-octane isoparaffins. The temperature of the upper reaction zone is optimized for conversion of
nC5 to iC5 , and the temperature of the lower reaction zone is optimized for conversion
of n-hexanes and methyl pentanes to di-methyl butanes.
The isomerization reactions take place over a fixed-bed of catalyst. Hydrocarbons
enter the base of the reaction zone, and are mixed with hydrogen (H2 )-rich gas
Compressor
Gas C1–C4
HBG
dryer
Product RON 91–92
H/T feed
Bottom product
before passing upwards through the catalytic layer. Reaction products (iso-paraffins)
are immediately fractionated away from the reaction zone as they are produced,
concentrating the reactants (n-paraffins) in the catalytic layer. Continuously
concentrating reactants within the catalyst facilitates a higher conversion than can
be achieved in a traditional fixed-bed reactor, as these are limited by the reaction
equilibrium. Side reactions are also minimized by removing the reaction products
quickly after they are produced. Any unconverted n-paraffins leaving the top of the
bed are returned to the bottom of the bed by reflux.
The overhead gas is cooled and routed to a high-pressure separator, where
recycle H2 -rich gas is recovered. Liquid from the high-pressure separator is routed to
the low-pressure reflux drum. The top product (C5 isomerate) is pressured away and
may be combined with the middle and bottom products as required.
A liquid product is taken from the middle of the column between the main
reaction stages. This middle product is nominally C6 isomerate, which is cooled before
being combined with the top product.
Continued 
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Isomerization—MAX-ISOM™ (cont.)
The heavier C6 hydrocarbons, and any higher boiling hydrocarbons entering with
the feed, are stripped in the bottom section of the column. Liquid is withdrawn from the
base of the column and cooled before being combined with the top product and middle
product, or being routed to another destination. The column reboil is conventional.
By its nature, the C5 /C6 isomerate product has a very-high octane number,
which can be equivalent to a conventional fixed-bed unit operating with both a
de-isopentanizer and de-isohexanizer.
A makeup of H2-rich gas is required. This product is combined with recycled
H2-rich gas, and routed to a knock-out drum to remove free liquid before entering
the recycle compressor. After cooling, the gas is dried to less than 5 ppm (vol) by an
adsorption dryer. The dry gas is divided into separate streams, as required, and routed
to the catalytic zones of the catalytic distillation column. C7 isomerization is achieved
in exactly the same way as described above, but will require a C7 isomerization
reaction layer and a modified column temperature profile.
Advantages:
• High product quality
• Compact design
• Low cost
• Feed flexibility
Licensors: KBR and RRT Global
Contact: technologyconsulting@kbr.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Isomerization—Snamprogetti™
Iso/OctEne/Iso-OctAne Technology,
(SP-Iso/SP–IsoH)
Application: The Snamprogetti dimerization/hydrogenation technology is used to
produce isoctene/isooctane high-octane compounds (rich in C8 ) for gasoline blending.
2
Oxygenate feed
Feed: C4 streams from the steam cracker, fluid catalytic cracking (FCC) and isobutane
dehydrogenation units with isobutene contents ranging from 15 wt%–50 wt%.
Iso-OctEne and Iso-OctAne streams contain at least 85 wt% of C8, with less
than 5,000 ppm of oligomers higher than C12.
Description: Depending on the conversion and investment requirements, various
options are available to reach isobutene conversion ranging from 85 wt%–99 wt%.
Oxygenates, such as methanol, methyl tertiary butyl ether (MTBE) and/or
tert-butyl alcohol (TBA), are used as “selectivators” to improve selectivity of the
dimerization reaction while avoiding the formation of heavier oligomers.
A high conversion level of isobutene (99 wt%) can be reached with a doublestage configuration where, in both stages, water-cooled tubular reactors (WCTR),
(1) and (2), are used for the isobutene dimerization to maintain an optimal
temperature control inside the catalytic bed.
The reactors effluents are sent to two fractionation columns, (3) and (5), to
separate the residual C4 from the mixture oxygenate-dimers. At the end, the oxygenates
are recovered from raffinate C4 (6) and from dimers (4), and then recycled to reactors.
The isooctene product collected at the bottom of the column (4) can be sent
to storage or fed to the hydrogenation unit (7) to produce the saturate hydrocarbon
stream–isooctane.
Due to a joint development agreement between Saipem and CB&I Technology for
the isobutene dimerization (Dimer8 process), the plant configuration can be optionally
modified with the introduction of a catalytic distillation column to have an alternative
scheme that is particularly suitable for revamping refinery MTBE units.
Advantages: High production and operative flexibility; easy maintenance and startup;
high runtime.
Economics:
Utilities: (Referred to a feedstock from isobutane dehydrogenation at 50 wt%
isobutylene concentration)
5
6
3
C4 raffinate
1
4
C4 feed
Isooctene
Electricity
Steam, MP and LP
Water, cooling (rise 10°C)
7
Isooctane
15 kWh/t isooctene
0.6 t/t isooctene
51 m³/t isooctene
Development/delivery: In the field of high-quality fuel components, Saipem has
successfully implemented several “first-of-a-kind” technologies:
• 1997—First isooctene production in the world (Italy)
• 2012—First DIB (isooctene) plant in operation in the world (Far East).
Installations: Five industrial tests have been carried out with different feedstocks,
and three units have been licensed by Saipem.
Licensor: Saipem S.p.A.
Website: www.saipem.com
Contact: Maura.Brianti@saipem.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Lubricants and Waxes—
BHTS Solvent Dewaxing
3
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
BHTS Dewaxing process, which removes waxy components from lubrication base-oil
streams to simultaneously meet desired low-temperature properties for dewaxed oils
and produce slack wax as a byproduct.
Description: Waxy feedstock (raffinate, distillate or deasphalted oil) is mixed with
a binary solvent system and chilled in a very closely controlled manner in scrapedsurface, double-pipe exchangers (1) and refrigerated chillers (2) to form a wax/oil/
solvent slurry.
The slurry is then filtered through the primary filter stage (3). The primary
filtrate, a dewaxed oil mixture, is first used to cool the feed/solvent mixture (1), and
then routed to the dewaxed oil recovery section (5) to separate solvent from oil.
Wax from the primary stage is slurried with cold solvent and filtered again in the
repulp filter (4) to reduce the oil content to approximately 10%.
The repulp filtrate is reused as dilution solvent in the feed chilling train.
The wax mixture is routed to a solvent-recovery section (6) to remove solvent from
the product streams (hard wax and soft wax). The recovered solvent is collected,
dried (7) and recycled back to the chilling and filtration sections.
Utilities: Typical per bbl of feed:
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
4
Refrigerant
Refrigerant
2
6
1
7
5
Solvent
recovery
Water
Steam
Waxy feed
Slack wax
Dewaxed
oil
Steam
Water
Refrigerant
Process stream
15
35
1,100
160,000
Installations: More than 100 units have been licensed and built.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Lubricants and Waxes—
Conventional Group II/III base oils
Application: The Shell conventional Group II/III base oils process converts heavy
hydrowax/unconverted oil streams, produced from dual-fuel lubricant or fuel
hydrocracker units, to base oils. This hydrowax has a high viscosity index and
low nitrogen, sulfur and low aromatics contents that make it suitable for conversion
into a range of marketable Group II/III base oils. The cold-flow properties are
improved through a noble metal catalytic dewaxing step. The remaining aromatic
rings are saturated in a hydrofinishing reactor filled with noble metal catalyst.
The resultant effluent is fractionated in a vacuum distillation column, where various
grades of base oil will be obtained.
Description: Paraffinic, unconverted oil—the bottom product of a hydrocracker
for which the feedstock is a waxy distillate [vacuum gasoil (VGO), de-asphalted
oil (DAO) or a blend of VGO with DAO, or with coker heavy gasoil], is a low-value
stream that can be converted in higher value products (i.e., Group II/III base oils).
These products require a low-sulfur content, so they need a hydrotreating/
hydrocracking step in the process lineup. The hydrotreating/hydrocracking process
objectives are to treat the nitrogen, sulfur and aromatics contents of the feedstock.
These reactions will boost the viscosity index of the hydrotreated effluent at
maximum viscosity retention.
The catalytic dewaxing process is a series of isomerization reactions that
convert normal paraffins, which cause base oils to have poor low-temperature
behavior, into isoparaffins. This improves the cold-flow properties (pour point, cloud
point and haze) of the feedstock required for meeting base oil quality specifications.
The aromatics content of Group II/III base oils should be lower than 1% to
ensure a stable product. Most of the aromatics are removed in the reactor(s) of the
hydrotreater/hydrocracker; the remainder are normally removed in a dedicated
hydrofinisher. This unit, which uses a noble metal catalyst, is required to reduce the
polyaromatics at low operating temperature to improve the base oil’s color
and oxidation stability.
The viscosities of the base oils are controlled by the cutting strategy in the
feedstock or product distillation column.
Advantages: This process ensures the production of high-quality base oils with
a high degree of saturation (> 99%), up to white oil quality. If Group II/III base oil
processes are integrated with a converting hydroprocess, they generate higher
yields than the Group I base oil process, which is known as the Solvex process. They
H2
Waxy
distillate
H2S
NH3
Light ends
Base oils Gr II/III
examples
SN 150
Hydrotreating
cracking unit
(HTU)/(HCU)
Catalytic
Fractionation
dewaxing
unit
Hydrowax unit (CDW)
Hydrofinishing
unit (HFU)
Fractionation SN 350
unit
SN 500
are typically low-complexity units. For lean hydroprocessing, it is expected that the
catalyst lifetime for the dewaxing and hydrofinishing steps will be usually longer than
6 yr for constant feedstock quality. The byproducts of this process, such as the
middle distillates, have excellent cold-flow properties (typical winter grade).
Development/Delivery: All the research and development programs supporting
the development of this process were carried out at Shell Technology Centre,
Amsterdam, the Netherlands, and included tests in units of various scales, from
micro-flow to bench-scale units. The catalyst supplier for this technology is Criterion
Catalysts & Technologies.
Installations: More than 15 new and revamp designs have been installed or are
under design. Revamps have been implemented in Shell or other licensors’ designs,
usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Lubricants and Waxes—Dewaxing
Application: Haldor Topsoe’s dewaxing technology is designed for production of all
grades of winter and arctic diesel fuels. By selecting the proper catalyst and operating
conditions, the cold flow properties can be improved while minimizing yield losses.
Description: Topsoe’s dewaxing technology is a combination of desulfurization and
dewaxing. The technology combines state-of-the-art reactor internals, engineering
expertise in quality design, high-activity treating catalyst and proprietary diesel
dewaxing catalyst. The process is suitable for new units or revamps of existing
hydrotreating units.
The treating section uses Topsoe’s high-activity CoMo or NiMo catalyst, such as
TK-578 BRIM® or TK-611 BRIM®, to remove sulfur to required product specification.
The desulfurized stream is treated in a downstream dewaxing reactor. The proprietary
dewaxing catalyst used in the application is dependent on the required reduction in
cold flow properties and can be selected for both sour and sweet mode operation.
Reactor section is followed by separation and stripping/fractionation where final
products are produced.
Like the conventional Topsoe hydrotreating process, the diesel upgrading
process uses Topsoe’s graded-bed loading and high-efficiency patented reactor
internals to provide optimal reactor performance and catalyst utilization.
Topsoe’s high-efficiency internals are effective for a wide range of liquid loading.
Topsoe’s graded-bed technology and the use of shape-optimized inert topping
material and catalyst minimize the pressure drop build-up, thereby reducing
catalyst skimming requirements and ensuring long catalyst cycle lengths.
Installations: One licensed dewaxing unit. Topsoe dewaxing catalysts have been
supplied to 17 hydrotreating units.
References:
1. Egeberg, R. G., N. H. Michaelsen and L. Skyum, “Novel hydrotreating technology
for production of green diesel”, ERTC, Berlin, November 2009.
2. R. G. Egeberg, N. H. Egeberg, S. Nyström, U. Kuylenstierna and K. Efraimsson,
“Turning over a new leaf in renewable diesel hydrotreating”, NPRA Annual
Meeting, Phoenix, Arizona, March 2010.
Hydrogen makeup
Recycle gas
compressor
Furnace
Pretreating
reactor
Dewaxing
reactor
Process gas
H2-rich
gas
Fresh feed
Naphtha
Product
fractionator
High-pressure
separator
Middle
distillate
Low-pressure
separator
Lube stock
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/products/catalytic-dewaxing
Contact: mkj@topsoe.com
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Lubricants and Waxes—
Extra-heavy base oils
Application: The Shell extra-heavy base oil licensed process for the production
of Group II extra-heavy base oils, primarily Group II bright stock, uses full-range
deasphalted oil (DAO) from a solvent deasphalting (SDA) unit as feedstock for an
integrated two-stage unit design (i.e., hydrotreating followed by a dewaxing and
hydrofinishing unit). The resultant effluent is fractionated in a vacuum distillation
column, where various grades of base oils are obtained (the bottom fraction
being bright stock oil).
Description: The DAO feedstock is sourced from an SDA unit using propane as
the solvent. The anticipated DAO lift is 25 wt%–45 wt%, depending on the
atmospheric residue/vacuum residue feed quality. This feed stream has a low
value and can be converted into higher-value products, such as Group II base oils
(eventually Group III base oils). These products require a low-sulfur content, so they
need a hydrotreating/hydrocracking step in the process lineup. The hydrotreating/
hydrocracking process objectives are to treat the nitrogen, sulfur and aromatics
contents of the feedstock. These reactions boost the viscosity index of the
hydrotreated effluent at maximum viscosity retention.
The catalytic dewaxing process is a series of isomerization reactions that
convert normal paraffins, which cause base oils to have poor low-temperature
behavior, into isoparaffins. This improves the cold-flow properties (pour point,
cloud point and haze) of the feedstock required for meeting base oil quality
specifications. Customized catalyst systems are suggested, depending on the
specifics of the feedstock.
The aromatics content of Group II/III base oils should be lower than 1% to
ensure a stable product. Most of the aromatics are removed in the reactor(s) of the
hydrotreater/hydrocracker; the remainder are normally removed in a dedicated
hydrofinisher. This unit, which uses a noble metal catalyst, is required to reduce the
polyaromatics at low operating temperature to improve the base oil’s color
and oxidation stability.
The viscosities of the base oils are controlled by the cutting strategy in the
feedstock or product distillation column. The fractionation technology can be
adopted to the feedstock or the intermediate stream’s viscosity profile.
Advantages: This process ensures the production of high-quality base oils with
high degree of saturation (> 99%), up to white oil quality. If Group II/III base oil
processes are integrated with a converting hydroprocess, they generate higher
VGO
VDU
Light ends
VR
AR
C3 SDA
DAO
HDT/HDW/HF/RDU
Asphaltenes
150/500 N
BS120
yields than the Group I base oil process, which is known as the Solvex process. They
are typically low-complexity units. For lean hydroprocessing, it is expected that the
catalyst lifetime for the dewaxing and hydrofinishing steps will be usually longer than
6 yr. for constant feedstock quality. The byproducts of this process, such as the
middle distillates, have excellent cold-flow properties (typical winter grade).
Development/Delivery: All the research and development programs supporting
the development of this process were carried out at Shell Technology Centre,
Amsterdam, the Netherlands, and included tests in units of various scales, from
micro-flow to bench-scale units. The catalyst supplier for this technology is Criterion
Catalysts & Technologies.
Installations: More than 15 base oil hydroprocessing unit new and revamp designs
have been installed or are under design. Revamps have been implemented in Shell
or other licensors’ designs, usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Furfural refining
Raffinate flasher
stripper
Extraction
tower
Application: A process to produce lube oil raffinates of high-viscosity index
from vacuum distillates and de-asphalted oil.
Raffinate mix
buffer
Description: This liquid-liquid extraction process uses furfural as the selective solvent
for removing aromatics and other impurities present in distillates and de-asphalted
oils. Furfural has a high solvent power for components that are unstable to oxygen, as
well as for other undesirable materials including color bodies, resins, carbon-forming
constituents and sulfur compounds. In the extraction tower, the feed oil is introduced
at the lower part of the extractor at a predetermined temperature. The raffinate
phase leaves at the top of the tower and the extract, which contains the bulk of the
furfural, is withdrawn from the bottom. The extract phase is then cooled and a socalled “pseudo raffinate” may be sent back to the extraction tower. Multi-stage solvent
recovery systems for raffinate and extract solutions secure energy efficient operation.
Raffinate
STM
Extract
flasher
stripper
Extract flash
system
Extract mix
settler
STM
Extract
Feeds: Vacuum distillate lube cuts and de-asphalted oils.
Products: Lube oil raffinates of high-viscosity indices. The raffinates contain all of the
desirable lubricating oil components present in the feedstock. The extract contains a
concentrate of aromatics that may be utilized as rubber oil or cracker feed.
Utilities: (Typical, Middle East crude; units per m³ of feed)
Electricity
20 kWh
MP steam
10 kg
LP steam
100 kg
Cooling water
30 m³
Fuel energy
20 kWh
Installations: Numerous installations under thyssenkrupp license are in operation
around the world.
STM
Solvent
drying
system
Water
stripper
STM
STM
Decanter
Feed
Feed
deaerator
Furfural stripper
buffer
Sewer
Licensor: thyssenkrupp. The former proprietor of this technology was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Furfural Refining℠ Lube Extraction
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
Furfural Refining lube extraction process, a solvent-extraction process that uses
furfural solvent to selectively remove undesirable components of low-quality
lubrication oil, which are naturally present in crude oil distillate and residual stocks.
This process selectively removes aromatics and compounds containing heteroatoms
(e.g., oxygen, nitrogen and sulfur). The unit produces paraffinic raffinates suitable for
further processing into lube base stocks.
Description: The distillate or residual feedstock and solvent are contacted in the
extraction tower (1) at controlled temperatures and flowrates required for optimum
counter-current, liquid-liquid extraction. The extract stream, containing the bulk of the
solvent, exits the bottom of the extraction tower, and is routed to a recovery section
to remove solvent contained in this stream. Solvent is separated from the extract oil
by multiple-effect evaporation (2) at various pressures, followed by vacuum flashing
and steam stripping (3) under vacuum. The raffinate stream exits the overhead of the
extraction tower and is routed to a recovery section to remove the furfural solvent
contained in this stream by flashing and steam stripping (4) under vacuum.
Overhead vapors from the steam strippers are condensed, combined with the
solvent condensate from the recovery sections, and distilled at low pressure to remove
water from the solvent. Furfural forms an azeotrope with water and requires two
fractionators. One fractionator (5) separates the furfural from the azeotrope, and the
second (6) separates water from the azeotrope. The water drains to the oily-water
sewer. The solvent is cooled and recycled to the extraction section.
Advantages: The raffinate produced may be dewaxed to make high-quality lube-base
oil, characterized by high-viscosity index, good thermal and oxidation stability, light
color and excellent additive response. The byproduct extracts, with high aromatic
content, can sometimes be used for carbon black feedstocks, rubber extender oils and
other non-lube applications.
2
3
4
Feed
6
5
1
Steam
Steam
Steam
Water
Refined oil
Extract
Installations: Over the last 60 years, this process has been or is being used
in more than 100 licensed units.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
Utilities: Typical per process bbl feed:
Electricity, kWh
2
Steam, lb
5
C.W. rise (25°F), gal
650
Fuel (absorbed), Btu
120,000
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Hydrofinishing/Hydrotreating
Reactor
Reactor feed
heater
Striper
STM
Vent gas
to heater
Application: A process to produce finished lube base oils and special oils.
Description: Feedstock is fed together with make-up and recycle hydrogen over
a fixed bed of catalyst at moderate temperature and pressure. The treated oil is
separated from unreacted hydrogen, which is recycled. Very high yields of product
are obtained.
The lube oil hydrofinishing process operates at medium hydrogen pressure,
moderate temperature and low hydrogen consumption.
Operating pressures of hydrogen finishing processes range from 25 bar–80 bar.
A higher pressure range affords greater flexibility with regard to base stock source
and product qualities. Oil color and thermal stability depend on treating severity.
Hydrogen consumption depends on feedstock and desired product quality.
STM
To fuel
gas (H2Sabsorption)
Makeup gas
compressor
Feeds: Solvent de-waxed lube stocks for lubricating oils ranging from spindle oil
to machine oil and bright stock.
Products: Finished lube oils (base grades or intermediate lube oils) and special oils
with specified color, thermal and oxidation stability.
Utilities: (Typical, Middle East crude; units per m³ of feed):
Electricity
15 kWh
MP steam
25 kg
LP steam
30 kg
Cooling water
20 m³
Makeup
hydrogen
Feed
Recycle gas
compressor
Dryer
STM
HP/LP
separator
Sour
water
Slop oil
Oil product
Installations: Numerous installations under thyssenkrupp license are in operation
around the world.
Licensor: thyssenkrupp. The former proprietor of this technology was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Hy-Finishing℠ Lube Hydrotreating
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
Hy-Finishing lube hydrotreating process, a specialized hydrotreating technology
that removes impurities and improves the quality of paraffinic and naphthenic lube
base oils. Normally, the hydrogen (H2 ) finishing unit is located in the processing
scheme between the solvent extraction and solvent dewaxing units for a lube plant
operating on an approved lube crude. In this application, the unit operates under
mild hydrotreating conditions to improve color and stability, reduce sulfur, nitrogen,
oxygen and aromatics, and remove metals.
Makeup H2
7
1
6
3
Feed
Description: The hydrocarbon feed is mixed with H2 (recycle plus makeup), preheated
and charged to a fixed-bed hydrotreating reactor (1). The reactor effluent is cooled in
a cross-exchanger with the mixed feed-hydrogen stream, before undergoing gasliquid separation in two stages: first in the hot separator (2), and then in the cold
separator (3). The condensed hydrocarbon liquid streams from each of the two
separators are sent to the product stripper (4) to remove the remaining gas and
unstabilized distillate from the lube oil product. The product is then dried in a vacuum
flash (5). Gas from the cold separator is amine-scrubbed (6) to remove H2 S before
being compressed in the recycle H2 compressor (7) and returned to the feed.
Utilities: Typical per bbl feed:
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
5
15
400
20,000
Amine
Unstable naphtha
2
Steam
4
5
Lube oil
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Hy-Raff℠ Lube Hydrotreating
Makeup H2
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
Hy-Raff lube hydrotreating process, a new hydrotreating technology that upgrades
standard Group I lube-base oils to produce Group II base oils by hydrotreating
raffinates from an extraction unit of a solvent-based lube oil plant. Sulfur is reduced
below 0.03 wt%, and saturates are increased to greater than 90 wt%.
Description: The hydrocarbon feed is mixed with hydrogen (recycle plus makeup),
preheated and charged to a fixed-bed hydrotreating reactor (1). The reactor effluent
is cooled in a cross-exchanger with the mixed feed-hydrogen (H2 ) stream, before
undergoing gas-liquid separation in two stages: first in the hot separator (2), and then
in the cold separator (3). The condensed hydrocarbon liquid streams from each of the
two separators are sent to the product stripper (4) to remove the remaining gas and
unstabilized distillate from the lube oil product. The product is then dried in a vacuum
flash (5). Gas from the cold separator is amine-scrubbed (6) to remove hydrogen
sulfide (H2 S) before being compressed in the recycle H2 compressor (7) and returned
to the feed.
Advantages: The product is a lube-base oil of sufficient quality to meet Group II
specifications. Product color is significantly improved over standard-base oils. Middle
distillate byproducts are of sufficient quality for blending into diesel.
Economics: This process allows the operator of an existing base-oil plant to costeffectively upgrade base oil products to the new specifications rather than scrapping
the existing plant and building an expensive new hydrocracker-based plant.
Utilities: Typical per bbl feed:
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
7
1
6
Amine
3
Feed
Unstable naphtha
2
Steam
4
5
Lube oil
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
5
15
200
70,000
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
ISODEWAXING®
Makeup H2
Application: Selectively convert feedstock’s waxy molecules by isomerization
in the presence of ISODEWAXING catalysts. The high-quality products can meet
stringent cold-flow properties and viscosity index (VI) requirements for Group II
or Group III base-oils.
Description: ISODEWAXING catalysts convert feedstocks with waxy molecules
(containing long, paraffinic chains) into two or three main branch isomers that have
low-pour points. The product also has low aromatics content. Typical feeds are:
raffinates, slack wax, foots oil, hydrotreated VGO, hydrotreated DAO and unconverted
oil from hydrocracking.
As shown in the simplified flow diagram, waxy feedstocks are mixed with recycle
hydrogen (H2 ) and fresh makeup H2 , heated and charged to a reactor containing
ISODEWAXING catalyst (1). The effluent will have a much lower pour point and,
depending on the operating severity, the aromatics content is reduced by 50%–80%
in the dewaxing reactor.
In a typical configuration, the effluent from a dewaxing reactor is cooled down
and sent to a finishing reactor (2), where the remaining single ring and multiple ring
aromatics are further saturated by the ISOFINISHING catalysts. The effluent is flashed
in high-pressure and low-pressure separators (3, 4). Small amounts of light products
are recovered in a fractionation system (5).
Yields: The base oil yields strongly depend on the feedstocks. For a typical low-wax
content feedstock, the base oil yield can be 90%–95%. Higher wax feed will have
a little lower base oil yield.
Economics:
Investment: This is a moderate investment process; for a typical size
ISODEWAXING/ISOFINISHING unit, the capital for ISBL is approximately $9,000/bpsd.
Utilities: Typical per bbl feed:
Power, kWh
3.3
Fuel , kcal
13.4 x 103
Steam, superheated, required, kg
5.3
Steam, saturated, produced, kg
2.4
Water, cooling, kg
450
Chemical-H2 consumption, Nm3/m3 oil
30–50
Process gas
Naphtha
1
Diesel
Light base oil
3
6
4
Fresh feed
Jet
5
2
Medium base oil
Heavy base oil
Installations: Thirty five units are in various stages of operation, design or construction.
References:
1. Meyers, R. A., Handbook of Petroleum Refining Processes, 4th Ed., McGraw-Hill,
2016.
Licensor: Chevron Lummus Global LLC
Website: www.chevronlummus.com
Contact: SBhattacharya@chevron.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—MP Refining
Raffinate
stripper
Application: A process to produce lube oil raffinates of high-viscosity index
from vacuum distillates and de-asphalted oil.
Extraction
tower
Description: The feed and N-Methyl-2-Pyrrolidone (MP) enter the treating tower
at controlled temperatures and flowrates required for optimum counter-current
extraction of the oil. The raffinate mix leaves from the top of the extraction tower
and flows through heat exchangers and a fired heater to the raffinate vacuum flash
tower. Most of the MP is vaporized from the raffinate for recycle to the extraction
tower. Raffinate from the flash tower flows to the raffinate stripper, where it is
steam-stripped of MP.
The MP-rich extract mix exits from the bottom of the treating tower, and then
is heat exchanged and passed through a triple effect evaporation system for MP
removal. The extract is stripped free of MP with steam in the extract stripper.
MP is a highly selective solvent. A low solvent-to-oil ratio can be used with MP
to achieve the desired yield of a specified quality product.
Existing solvent refining units can be converted to MP to increase throughput
and/or reduce energy consumption. In the case of a grassroot unit, MP offers
significant savings in investment and operating costs over most other solvents.
Raffinate
STM
Extract flash
tower
Extract mix
settler
Extract
stripper
STM
Extract
STM
Feeds: Paraffinic or naphthenic lubricating oil distillates and de-asphalted oils.
The solvent used is N-Methyl-2-Pyrrolidone (MP).
Products: High-quality raffinates suitable (after dewaxing if the feedstock is paraffinic)
for use in blending into the highest quality motor oils and industrial products.
Utilities: (Typical, Middle East crude; units per m³ of feed):
Electricity
15 kWh
MP steam
5 kg
LP steam
80 kg
Cooling water
20 m³
Fuel energy
200 kWh
Installations: Numerous installations under thyssenkrupp license are in operation
around the world.
Feed
Sewer
Feed deaerator
Drying tower
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
Licensor: thyssenkrupp. The former proprietor of this technology was ThyssenKrupp
Uhde GmbH.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
MP Refining℠ Lube Extraction
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the MP
Refining lube extraction process, a solvent-extraction process that uses N-methyl-2pyrrolidone (NMP) solvent to selectively remove undesirable components of lowquality lubrication oil, which are naturally present in crude oil distillate and residual
stocks. This process selectively removes aromatics and compounds containing
heteroatoms (e.g., oxygen, nitrogen and sulfur). The unit produces paraffinic or
naphthenic raffinates suitable for further processing into lube base stocks.
Description: The distillate or residual feedstock and solvent are contacted in the
extraction tower (1) at controlled temperatures and flowrates required for optimum
counter-current, liquid-liquid extraction. The extract stream, containing the bulk of the
solvent, exits the bottom of the extraction tower and is routed to a recovery section
to remove solvent contained in this stream. Solvent is separated from the extract oil
by multiple-effect evaporation (2) at various pressures, followed by vacuum flashing
and steam stripping (3) under vacuum. The raffinate stream exits the overhead of
the extraction tower and is routed to a recovery section to remove the NMP solvent
contained in this stream by flashing and steam stripping (4) under vacuum.
Overhead vapors from the steam strippers are condensed, combined with solvent
condensate from the recovery sections, and distilled at low pressure to remove water
from the solvent (5). Solvent is recovered in a single tower because NMP does not
form an azeotrope with water, as does furfural. The water drains to the oily-water
sewer. The solvent is cooled and recycled to the extraction section.
Advantages: The raffinate produced may be dewaxed to make high-quality, lubebase oil characterized by high-viscosity index, good thermal and oxidation stability,
light color and excellent additive response. The byproduct extracts with high aromatic
content can sometimes be used for carbon black feedstocks, rubber extender oils and
other non-lube applications.
Investment: NMP has superior extraction power relative to furfural and phenol, resulting
in reduced solvent circulation requirements, resulting in lower capital cost and utilities.
Utilities: Typical per bbl feed:
Electricity, kWh
Steam (pressure), lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
2
3
4
Feed
5
1
Steam
Steam
Water
Refined oil
Extract
Installations: This process is being used in 15 licensed units, of which eight are
units converted from phenol or furfural, with another three units under license for
conversion.
References:
1. “Trends in solvent extraction of base oils,” International Conference on
Information Systems (ICIS) Base Oils and Lubricants Conference, 2017.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
2
5
600
100,000
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COMPANY INDEX
Lubricants and Waxes—
Naphthenic base oils
Application: The Shell integrated process for naphthenic base oils converts vacuum
liquid-hydrocarbon streams, sourced from naphthenic and semi-naphthenic crudes,
in to base oils. The integrated process unit contains a first-stage hydrotreating/
dewaxing unit and a second-stage hydrofinishing step. This integrated process
enables the production of high-quality, Group V base oils (naphthenic base oils)
for use in the food and medical industries.
Description: Naphthenic and semi-naphthenic feedstocks are characterized by
having no or very little wax (0 wt%–4 wt%). If the feed has no wax, lineups without
a dewaxing step can be used. However, refineries are increasingly being confronted
by naphthenic feeds with a very low wax content that leads to cold-flow properties
(pour point) issues for the final base oils. Here, a dewaxing step is required to
improve the cold-flow properties. A base metal dewaxing catalyst will be suitable
for converting the normal paraffins by cracking reactions. A lean and simple unit
lineup can be used, and first-stage dewaxing can be applied. Although the dewaxing
catalyst is a cracking-type catalyst, high yields will be achieved, as the amount
of wax to be cracked is very low.
In the hydrotreater/hydrocracker, sufficiently high reactor temperatures are
required to remove most of the monoaromatics. Many of the polyaromatics will also
be removed, but there is a chance that some polyaromatics will reform at the high
temperatures. Consequently, a dedicated hydrofinishing unit, using a noble metal
catalyst, is required to reduce the polyaromatic levels at low operating temperatures.
The layout of the reactors of the hydroprocessing unit can vary from case
to case. For each case, it is necessary to check whether both hydrotreating and
hydrocracking catalysts are required in the hydrotreating/hydrocracking section,
as just a hydrotreating catalyst will be sufficient to meet the required specifications
in some cases.
All the catalysts used in this first-stage integrated system need to be sulfided.
Therefore, the dewaxing catalyst can be placed in series, in a separate reactor or
stacked, in the same reactor with hydrotreating catalyst. A layer of finishing catalyst
(usually the same catalyst as the hydrotreating catalyst) is loaded just below the
dewaxing catalyst to hydrogenate at a lower temperature the (remaining) olefins
formed during the dewaxing reactions.
If very severe hydrofinishing is required (e.g., in the production of naphthenic
medicinal white oils), the unit lineup will be more complicated. In such a line-up,
H2
Gr V base oils
examples
H 2S
NH3
Light/extra light
Heavy distillate/DAO
Hydrotreating/
catalytic
dewaxing unit
(HTU)/(CDW)
Hydrofinishing
unit (HFU)
Fractionation
unit
Medium
Heavy/extra heavy
a noble metal hydrofinishing catalyst gives the best results. This method requires
a second-stage operation. The lineup will then be similar to the lineup presented,
but with only hydrofinishing catalyst in the second stage. In this lineup, a layer of
base metal hydrofinishing catalyst immediately below the dewaxing catalyst
bed is still recommended (i.e., to saturate olefins immediately and to avoid the
recombination of hydrogen sulfide to form mercaptans).
The viscosities of the base oils are controlled by the cutting strategy in the
product distillation column.
Operating conditions: Both full-range and batch mode can be applied to
this process. The pressure range is 130 bar–170 bar. The temperature range is
340°C–390°C for hydrotreating/dewaxing and 220°C–260°C for hydrofinishing.
Yields: The hydrotreating/dewaxing yield is 80% weight on feed; and the
hydrofinishing yield is > 99% weight on feed
Advantages: The Group V base oil conversion process will generate high yields of
base oils. For lean hydroprocessing, it is expected that the catalyst lifetime for the
dewaxing and hydrofinishing steps will be usually longer than 4 years for constant
feedstock quality. This process enables the production of white oil for food and
medical applications.
Continued 
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Lubricants and Waxes—Naphthenic base oils (cont.)
Development/Delivery: All research and development programs supporting
the development of this process were carried out at Shell Technology Centre,
Amsterdam, the Netherlands, and included tests in units of various scales, from
micro-flow to bench-scale units. The catalyst supplier for this technology is Criterion
Catalysts & Technologies.
Installations: More than 15 new and revamp designs have been installed or are
under design. Revamps have been implemented in Shell or other licensors’ designs,
usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Paraffinic base oils
Application: The Shell integrated process for paraffinic base oils converts vacuum
liquid-hydrocarbon streams—sourced from paraffinic crudes—into paraffinic base oils.
The integrated process unit contains a first-stage hydrotreating/hydrocracking unit
and a second-stage dewaxing/hydrofinishing step. This integrated process enables
production of high-quality Group II/III base oils (paraffinic base oils).
Description: Paraffinic vacuum gasoil is a low-value waxy distillate that can be
converted into higher-value products (i.e., Group II/III base oils). These products
require a low-sulfur content, so require a hydrotreating/hydrocracking step in the
process lineup. The hydrotreating/hydrocracking process objectives are to treat the
nitrogen, sulfur and aromatics content of the feedstock. These reactions boost the
viscosity index of the hydrotreated effluent at maximum viscosity retention.
The hydrotreated effluent is processed in a dewaxing unit, using noble metal
catalyst, to improve the cold-flow properties. The catalytic dewaxing process is a
series of isomerization reactions that convert normal paraffins, which cause base oils
to have poor low-temperature behavior, into isoparaffins. This improves the cold-flow
properties (pour point, cloud point and haze) of the feedstock required for meeting
base oil quality specifications.
In the hydrotreater/hydrocracker, sufficiently high reactor temperatures are
required to remove most of the monoaromatics. Many of the polyaromatics will
also be removed, but there is a chance that some polyaromatics will reform at the
high temperatures. Consequently, a dedicated hydrofinishing unit–using a catalyst–
is required to reduce the polyaromatic levels at low operating temperatures. The
viscosities of the base oils are controlled by the cutting strategy in the product
distillation column.
Advantages: This process ensures the production of high-quality base oils with high
degree of saturation (> 99%), up to white oil quality. If Group II/III base oil processes
are integrated with a converting hydroprocess, they generate higher yields than the
Group I base oil process, which is known as the Solvex process. They are typically lowcomplexity units. For lean hydroprocessing, it is expected that the catalyst lifetime
for the dewaxing and hydrofinishing steps will be usually longer than 6 yr for constant
feedstock quality. The byproducts of this process, such as the middle distillates,
have excellent cold-flow properties (typical winter grade).
H2
Waxy
distillate
H 2S
NH3
Gr II/III base oils
examples
Light/extra light
Hydrotreating/
hydrocracking
unit
(HTU)/(CDW)
Catalytic
dewaxing
unit (CDW)
Hydrofinishing
unit (HFU)
Fractionation
unit
Medium
Heavy/extra heavy
Development/Delivery: All research and development programs supporting the
development of this process were carried out at Shell Technology Centre, Amsterdam,
the Netherlands, and included tests in units of various scales, from micro-flow to
bench-scale units. The catalyst supplier for this technology is Criterion Catalysts &
Technologies.
Installations: More than 15 new and revamp designs have been installed or are
under design. Revamps have been implemented in Shell or other licensors’ designs,
usually to debottleneck and increase feed heaviness.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—Revivoil™
Application: The Revivoil process can be used to produce high yields of premium
quality lube bases from spent motor oils. Requiring neither acid nor clay treatment
steps, the process can eliminate the environmental and logistical problems of waste
handling and disposal associated with conventional re-refining schemes.
Description: Spent oil is distilled in an atmospheric flash distillation column to remove
water and gasoline, and then sent to the thermal deasphalting (TDA) vacuum column
for recovery of gasoil overhead and oil bases as side streams. The energy-efficient TDA
column features excellent performance with no plugging and no moving parts. Metals
and metalloids concentrate in the residue, which is sent to an optional Selectopropane
unit for bright stock production and asphalt recovery. This scheme is different from
those for which the entire vacuum column feed goes through a deasphalting step.
Revivoil’s energy savings are significant, and the overall lube oil base recovery is
maximized. The results are substantial improvements in selectivity, quality and yields.
The final, and very important, step for base oil quality is a specific hydrofinishing
process that reduces or removes remaining metals and metalloids, Conradson carbon,
organic acids and compounds containing chlorine, sulfur and nitrogen. Color, UV and
thermal stability are restored and polynuclear aromatics are reduced to values far
below the latest health thresholds. The viscosity index (VI) remains equal to or better
than the original feed. For metal removal (> 96%) and refining-purification duty, the
multicomponent catalyst system is the industry’s best.
Product quality: The oil bases are premium products—all lube oil base specifications
are met by Revivoil processing from Group I through Group II of API base stocks
definitions. Additionally, a diesel that is in compliance with EURO 5 requirements (low
sulfur) can be obtained.
Health and safety and environment: The high-pressure process is in line with
European specifications concerning carcinogenic PNA compounds in the final product
at a level inferior to 5 wppm (less than 1 wt% PCA—IP346 method).
Water, gasoline
Light ends
Water and
lights removal
Gasoil
Hydrotreated gasoil
TDA
column
Hydrofinishing
Base
oils
Spent oil
DAO
(Optional)
H2
Selectopropane
Asphalt
Installations: Fourteen units have been licensed using all or part of
the Revivoil technology.
Licensor: Axens and Viscolube.
Website: www.axens.net/product/technology-licensing/10061/revivoil.html
Contact: www.axens.net/contact.html
Economics: The process can be installed stepwise or entirely. A simpler scheme
consists of the atmospheric flash, TDA and hydrofinishing unit, and enables 70%–80%
recovery of lube oil bases. The Selectopropane unit can be added at a later stage to
bring the oil recovery to the 95% level on dry basis. For two plants of equal capacity,
payout times before taxes are 2 yr in both cases.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Solvent Lube Dewaxing
Application: A process to produce dewaxed oils and slack waxes.
Description: Light, medium and heavy cuts are chilled at carefully controlled rates.
Solvent (e.g., a mixture of MEK and toluene) is added incrementally in the chilling
train. Filtration is carried out in two stages. The wax from the “primary” filters contains
substantial amounts of dewaxed oil. This “wax“ is re-slurried with additional cold
solvent, re-filtered and washed in the second stage, the “re-pulp” filter. Filtrate from
the primary filter is sent to the solvent recovery section, while the filtrate from the
secondary filter is used as solvent in the tile incremental dilution system. The solvent
recovery is carried out in three stages for energy-efficient operation.
Chiller
Secondary
filters
Water settler
and surge tank
Solvent
fractionator
Wax mix flash
section
Refrig.
STM
Refrig.
Feeds: Solvent refined lube stocks or raw stocks of any viscosity and density.
Main
filtrate
Products: Dewaxed oils with specified pour points. Slack waxes with oil contents
of 5%–10%. In the case of a combined dewaxing/de-oiling plant, de-oiled waxes
with less than 1% oil or with specified penetration values could be produced by
adding a third filter stage.
Utilities: (Typical, Middle East crude; units per m³ of feed):
Electricity
100 kWh
LP steam
230 kg
Cooling water
50 m³
Fuel energy
400 kWh
Primary
filters
STM
Slack wax
Sewer
Repulp
filtrate
STM
DWO mix
Dewaxed oil
Raffinate
Exchanger
Solvent receiver
DWO flash towers
DWO stripper
Installations: Numerous installations under thyssenkrupp license are in operation
around the world.
Licensor: thyssenkrupp. The former proprietor of this technology was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
Solvent Wax Deoiling
Application: The process produces high-melting and low-oil containing hard wax
products for a wide range of applications.
Description: Warm slack wax is dissolved in a mixture of solvents and cooled by heat
exchange with cold main filtrate. Cold wash filtrate is added to the mixture, which is
chilled to filtration temperature in scraped-type coolers. In Stage 1, crystallized wax is
separated from the solution in a rotary drum filter. The main filtrate is pumped to the
soft-wax solvent recovery section. Oil is removed from the wax cake in the filter by
thorough washing with chilled solvent.
The wax cake of the first filter stage consists mainly of hard wax and solvent,
but still contains some oil and soft wax. Therefore, it is blown off the filter surface,
mixed again with solvent and re-pulped in an agitated vessel. From there, the slurry
is fed to the filter (Stage 2), and the wax cake is washed again with oil-free solvent.
The solvent containing hard wax is pumped to a solvent recovery system. The filtrate
streams of filter Stage 2 are returned to the process: the main filtrate as initial dilution
to the crystallization section, and the wash filtrate as re-pulp solvent. The solvent
recovery sections serve to separate solvent from the hard wax and from the soft wax,
respectively. These sections yield oil-free hard wax and soft wax (or foots oil).
Feeds: Different types of slack waxes from lube dewaxing units, including
macrocrystalline (paraffinic) and microcrystalline wax (from residual oil).
Oil contents typically range from 5 wt%–25 wt%.
Products: Wax products with an oil content of less than 0.5 wt%, except
for the microcrystalline paraffins, which may have a somewhat higher oil
content. The de-oiled wax can be processed further to produce high-quality,
food-grade wax.
Utilities: (Slack wax feed containing 20 wt% oil, per metric ton of feed):
Electricity
80 kWh
LP steam
150 kg
Cooling water
50 m³
Fuel energy:
400 kWh
Chiller
Primary
filters
Secondary
filters
Water settler
and surge tank
Solvent
fractionator
Wax mix flash
section
Refrig.
STM
Refrig.
Main
filtrate
STM
Hard wax
Sewer
Repulp
filtrate
STM
DWO mix
Soft wax
Slack wax
Exchanger
Solvent receiver
DWO flash towers
DWO stripper
Licensor: thyssenkrupp
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
Installations: Wax de-oiling units have been added to existing solvent
dewaxing units in several lube refineries, or as stand-alone units.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—Wax
Fractionation℠ Solvent Dewaxing
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
Wax Fractionation solvent dewaxing process, which removes waxy components
from lubrication base-oil streams to simultaneously meet desired low-temperature
properties for dewaxed oils and produce both soft and hard waxes as byproducts.
Bechtel’s two-stage solvent dewaxing process can be expanded to simultaneously
produce hard wax by adding a third de-oiling stage, using the Wax Fractionation
process, as described below.
Description: Waxy feedstock (raffinate, distillate or deasphalted oil) is mixed with a
binary-solvent system and chilled in a closely controlled manner in scraped-surface,
double-pipe exchangers (1) and refrigerated chillers (2) to form a wax/oil/solvent slurry.
The slurry is then filtered through the primary filter stage (3) and primary
filtrate, a dewaxed oil mixture, is first used to cool the feed/solvent mixture (1),
and then routed to the dewaxed oil recovery section (6) to separate solvent from oil.
Wax from the primary stage is slurried with cold solvent and filtered again in the
repulp filter (4) to reduce the oil content to approximately 10%.
The repulp filtrate is reused as dilution solvent in the feed chilling train. The lowoil content slack wax is warmed by mixing with warm solvent to melt the low-melting
point waxes (soft wax), and is filtered in a third-stage filtration (5) to separate it from
the hard wax. The soft and hard wax mixtures are each routed to a dedicated solventrecovery section (7,8) to remove solvent before the recovered solvent is collected,
dried (9) and recycled back to the chilling and filtration sections.
Utilities: Typical per bbl feed
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
25
25
1,500
230,000
3
4
5
Refrigerant
Refrigerant
2
7
8
Hard wax
1
9
6
Solvent
recovery
Steam
Waxy feed
Dewaxed
oil
Soft wax
Water
Steam
Water
Refrigerant
Process stream
Installations: Seven units are now in service.
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—Wax
Hy-Finishing℠ Hydrotreating
Application: Bechtel Hydrocarbon Technology Solutions Inc. (BHTS) offers the
Wax Hy-Finishing hydrotreating process, which has largely replaced clay treatment
of low-oil content waxes to produce food and medicinal grade product specifications
(color, UV absorbency and sulfur) in new units.
Description: The hard wax feed is mixed with hydrogen (in some cases, recycle plus
makeup), preheated, and charged to a fixed-bed hydrotreating reactor (1). The reactor
effluent is cooled in a cross-exchanger with the mixed feed-hydrogen stream, before
undergoing gas-liquid separation in two stages: first in the hot separator (2), and then
in the cold separator (3). The condensed hydrocarbon liquid stream from each of the
two separators are sent to the product stripper (4) to remove the remaining gas and
unstabilized distillate from the wax product. The product is then dried in a vacuum
flash (5). If the design is for once-through hydrogen (H2 ), as it is in this case, gas from
the cold separator is purged from the unit. If designed for recycle, it is compressed and
recycled to the feed.
Advantages: Wax Hy-Finishing advantages include lower operating costs, elimination
of environmental concerns regarding clay disposal and regeneration, and higher net
wax product yields.
Utilities: Typical per bbl feed:
Electricity, kWh
Steam, lb
C.W. rise (25°F), gal
Fuel (absorbed), Btu
5
25
300
30,000
1
Off-gas
3
Feed
2
H2
Unstable naphtha
4
5
Wax Product
Licensor: Bechtel Hydrocarbon Technology Solutions Inc.
Website: www.bechtel.com/bhts
Contact: bhts@bechtel.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Lubricants and Waxes—
White Oil and Wax Hydrogenation
Application: A process to produce technical/medical white oils and food grade waxes.
First stage
Technical white oil or refined wax
Food- or medicinal-grade white oil
Reactor
Reactor
H2
recycle
Electricity, kWh
LP steam, kg
Cooling water, m³
Hydrogen, kg
1st stage for
technical white oil
100
500
48
10
2nd stage for
medical white oil
100
400
20
2.6
Food-grade
wax
70
140
7
1.6
H2
recycle
Stm.
Food- or
medicinal-grade
white oil
Feed
Technical grade white oil or fully refined wax
Products: Technical and medical grade white oils and waxes, e.g., for plasticizer,
textile, cosmetic, pharmaceutical and food industries. Products are in accordance
with the US Food and Drug Administration (FDA) regulations and the German
Pharmacopoeia (DAB 8 and DAB 9) specifications.
Utilities: (Typical, Middle East crude; units per m³ of feed):
Tailgas
Purge
Makeup H2
Description: This catalytic hydrogenation process uses two reactors. Hydrogen
(H2 ) and feed are heated upstream of the first reaction zone and are separated
downstream of the reactors into the main product and by-products [hydrogen sulfide
(H2 S) and light hydrocarbons]. The use of a stripping column permits the adjustment
of product specifications for technical grade white oil or feed to the second
hydrogenation stage. When hydrogenating waxes, medical quality is obtained in the
one-stage process.
In the second reactor, the feed is passed over a highly active hydrogenation
catalyst to achieve a very low level of aromatics, particularly polynuclear compounds.
This scheme permits each stage to operate independently and to produce technical
or medical grade white oils separately.
Feeds: Non-refined as well as solvent-refined naphthenic or paraffinic vacuum
distillates or de-oiled waxes.
Second stage
Installations: Four installations are using the thyssenkrupp proprietary technology,
one of which has the largest capacity worldwide.
Licensor: thyssenkrupp. The former proprietor of this technology was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com, dorothe.weimer@thyssenkrupp.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Olefins—Butenex® Process
C4 paraffins
Application: The BUTENEX Process is a technology for the separation of pure C4
olefins from various olefinic/paraffinic C4 feedstocks, e.g., from an ethylene cracker
or FCCU, via extractive distillation using a selective solvent or a solvent mixture.
Description: In the extractive distillation (ED) process, a single-compound solvent,
n-formylmorpholine (NFM), or NFM in a mixture with another solvent (typically
a morpholine derivative), alters the vapor pressure of the components being
separated. The vapor pressure of the olefins is lowered more than that of the less
soluble paraffins. Paraffinic vapors leave the top of the ED column, and solvent
with olefins are drown off the bottom of the ED column.
The bottom product of the ED column is fed to the stripper to separate pure
olefins (mixtures) from the solvent. After a highly integrated heat exchanger, the lean
solvent is recycled to the ED column. The solvent, either NFM or a mixture including
NFM, satisfies the solvent properties by providing high selectivity and capacity,
thermal stability and a suitable boiling point.
Economics:
Product purity
butene content
Solvent content
Extractive
distillation
column
C4 fraction
C4 olefins
Stripper
column
Solvent + C4 olefins
99 wt%
1 wt% ppm max.
Consumption (typical) per metric ton of FCC C4 fraction feedstock:
Steam
500 kg–800 kg
Water
15 m3
Cooling electricity
25 kWh
Installations: Two commercial plants for the recovery of pure n-butenes
have been installed since 1998.
Solvent
Licensor: thyssenkrupp. The former proprietor of this process was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Olefins—CRYO-PLUS™ Recovery
of Olefins from Refinery Off-gas
Application: Recovery of valuable olefins products from low-pressure, hydrogen
(H2 )-bearing refinery off-gas, with less energy required than traditional liquid recovery
processes to improve feedstock availability, resulting in higher product yields with less
flaring and nitrogen oxide (NOx ) emissions. Additionally, the CRYO-PLUS process can
produce H2 as a residue gas stream with modifications to the flow scheme.
Description: Fluid catalytic cracking (FCC) and catalytic reforming processes convert
crude products (naphtha and gasoils) into high-octane, unleaded gasoline blending
components (reformate and FCC gasoline). Cracking and reforming processes
produce large quantities of both saturated and unsaturated gases.
Excess fuel gas overloads refinery gas recovery processes. As a result, large
quantities of olefins are lost to the fuel system. Many refineries produce more fuel gas
than they use, resulting in frequent flaring of the excess gas.
CRYO-PLUS recovers propylene and propane (C3s), butylenes and butanes (C4s)
and ethylene (C2) and heavier hydrocarbons from the excess gas.
Feed conditioning: Feeds may first pass through a coalescing filter/separator
designed to remove solid particles and liquid droplets that may carry over from
upstream processes. An amine treating unit for removal of acid gas components
removes these compounds in an absorption process.
Feed compression: The feed stream is compressed unless already at elevated
pressures. An air cooler or cooling water cools the gas downstream of the compressor.
Heat of compression can also be used as a heat source for fractionation as permitted
by the process heat balance and temperature driving force.
Dehydration: Water content of the gas is reduced through adsorption in
molecular sieve desiccant beds. This is a batch process, where two or more adsorption
beds are used. One or more of the adsorption beds are regenerated to restore their
capacity, while the other bed(s) are on line and drying feed gas. A recycle portion of
the dry gas can be heated and used for regeneration of the beds to drive off adsorbed
water. A portion of the residue gas may also be used for the regeneration on a oncethrough basis.
Feed cooling: The feed gas flows into the cold section of the process, where
cooling by exchange of heat with the residue gas and cold separator liquids occurs via
brazed aluminum plate-fin heat exchanger. If needed, the gas may be further cooled
using external refrigeration in the cryogenic portion of the process.
From the dehydration
regeneration system
Residue gas to fuel
Expander
To the dehydration
regeneration system
Inlet gas from
dehydration
Feed CW
compressor
C3
Inlet heat
exchange
C3
Cold
separator
First
fractionator
Second
fractionator
Steam
Condensate
Liquid product
Cold separation: The feed gas is partially condensed and delivered to a separator.
Liquid flows through the inlet exchanger to cool feed gas before entering the
de-ethanizer (or de-methanizer for C2 recovery) for fractionation. Vapor flows to the
expander/compressor and the gas expands, providing work/energy for compression.
Expansion and removal of energy further cool the gas, causing additional condensation.
The two-tower scheme produces a dry, stable heating value fuel and a liquid product
that may be fractionated further.
Operating conditions: Key control parameters, modes, pressure and
temperature ranges
Continued 
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Olefins—CRYO-PLUS™ Recovery of Olefins from Refinery Off-gas (cont.)
Yields: Typical propylene plus recovery:
Feed,
Residue gas,
Liquid product,
Component
mol/hr
mol/hr
mol/hr
H2
1,274.66
1,274.66
0
H2S
0
0
0
CO
37.97
37.97
0
CO2
0
0
0
COS
0
0
0
N2
222.39
222.39
0
O2
5.42
5.42
0
C1
1,789.94
1,789.94
0
C2=
596.65
596.65
0.19
C2
884.12
888.13
0
C3=
309.17
7.45
301.72
C3
173.57
2.18
171.38
C4=
43.39
0
43.39
IsoC
32.54
0
32.54
NC
27.12
0
27.12
C5+
27.12
0
27.12
H2O
66.64
0
0
Totals
Mol/hr
5,489.68
4,820.6
603.44
Lb/hr
100,770.3
72,441.6
28,328.7
MMscfd
50
43.91
5.5
Bpd3,609
MMBtu/hr
2,412
1,812
601
Avg. mol wt
20.38
17.11
46.77
Btu/Scf
1,172.1
990.5
2,622.9
Typical ethylene plus recovery:
Feed,
Component
mol/hr
H2
1,274.66
H2S
0
CO
37.97
CO2
0
COS
0
N2
222.39
O2
5.42
Residue gas,
mol/hr
1,274.66
0
37.97
0
0
222.39
5.42
Liquid product,
mol/hr
0
0
0
0
0
0
0
Recovery,
%
0
0
0.02
97.59
98.74
100
100
100
100
Recovery,
%
C1
1,789.94
1,789.94
0
C2=
596.65
58.35
0.19
C2
884.12
36.07
0
C3=
309.17
.99
301.72
C3
173.57
.40
171.38
C4=
43.39
0
43.39
IsoC
32.54
0
32.54
NC
27.12
0
27.12
C5+
27.12
0
27.12
H2O
66.64
0
0
Totals
Mol/Hr
5,489.68
3,426.02
603.44
Lb/Hr
100,770.3
31,492.5
28,328.7
MMscfd
50
31.204
5.5
Bpd11,451
MMBtu/hr
2,412
908
1,504
Avg. mol wt
20.38
12.12
34.62
Btu/Scf
1,172.1
698.6
1,984.1
0
0
0.02
97.59
98.74
100
100
100
100
Advantages:
• CRYO-PLUS improves the recovery of C3+ components, allowing refiners to
maintain a fuel gas balance while adding profits to the bottom line.
• Incrementally recovered propylene, butylene and isobutane become valuable
feeds for polymerization or alkylation processes, and result in higher conversion
of crude to high-octane gasoline.
• The removal of C3 and C4 components from fuel gas reduces NOx emissions.
• A higher recovery at reduced horsepower than competing technologies.
• CRYO-PLUS C2=™, an advanced design, recovers ethylene and heavier
hydrocarbons from low-pressure, H2-bearing refinery off-gas streams.
Installations: More than 20 installations in refineries.
References:
1. Bigger, K. and D. Goldbeck, “Recovery of light olefins and NGLS from refinery offgas”, AIChE Spring Meeting, April 2016
Licensor: Linde AG.
Website: www.leamericas.com/cryo-plus
Contact: sales@leamericas.com
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Olefins—FlexEne™
Application: Conversion of butene and pentene cuts into propylene.
Description: The worldwide demand for gasoline, diesel and petrochemicals is
shifting toward a greater emphasis on gasoline and propylene, and the flexibility
to meet changing demands will be vital for refinery profitability. Axens FlexEne
technology will expand the capabilities of the fluid catalytic cracking (FCC) process,
which is the main refinery conversion unit traditionally oriented to maximize
gasoline and, at times, propylene production.
FlexEne relies on the integration of an FCCU and an oligomerization unit called
Polynaphtha™, processing light FCC olefins and delivering good molecules back to
the FCCU. It provides the product flexibility required by the marketplace.
By adjusting the catalyst formulation and operating conditions, the FCC process
can operate in different modes: maxi-distillate, maxi-gasoline and high-propylene.
The combination with Polynaphtha delivers the flexibility expected by the market.
In a maxi-gasoline environment, the olefin-rich C4-FCC cut is usually sent to
an alkylation unit to produce alkylate, thus increasing the overall gasoline yield. In
most recent max-gasoline production schemes, alkylation has been advantageously
substituted by Polynaphtha, which delivers high-quality gasoline at a much lower cost.
For greater distillate production, Polynaphtha technology may be operated
at higher severity to produce distillates from C4 and C5 olefins. Additional diesel
production may be supplied by operating the FCCU in the maxi-distillate mode.
For greater propylene production, Axens proposes to process either the Polynaphtha
gasoline or distillate fractions to the FCCU, where they can be easily cracked to
produce propylene. Consequently, depending on market conditions, gasoline or diesel
can be recycled to the FCCU to produce high-value propylene from C4 and C5 olefins.
Thanks to the optimized combination of FCC and oligomerization, FlexEne
delivers the largest market product flexibility when targeting production of propylene,
and/or gasoline and/or distillates.
Installations: To date, Axens has been awarded more than 20 references for its
oligomerization technologies (Polynaphtha, PolyFuel®, Selectopol™ and FlexEne), and
several units are now in operation worldwide.
References:
1. “The FCC Alliance celebrates its 50th license in Philippines,” Petroleum
Technology Quarterly, pp. 16, 2Q 2011, March 2011.
Licensor: Axens
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/
73/oligomerization.html
Contact: www.axens.net/contact.html
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Olefins—IPA Process
Application: The thyssenkrupp IPA process (isopropanol) catalytically affects the direct
hydration of propene to form isopropanol. Compared with the sulfuric acid process,
the direct hydration technology features lower utility requirements, requires no
chemicals (such as sulfuric acid and nitric acid)—which eliminates corrosion problems
and significantly reduces maintenance cost—and generates no waste products.
Reactor/
HP-separator
LP-separator
Azeotrope
column
Drying
column
Water
IPA
separator extractor
Propylene
Propylene
recovery
Description: Liquid propene and water are heated to 130°C–140°C and then charged
to a downflow trickle bed reactor operating at a pressure of approximately 100 bar.
To minimize undesirable di- and trimerization reactions, an over-stoichiometrical
water-to-propene molar ratio is applied. The reactor is divided into multiple beds,
and the heat of reaction is removed by quenching with cold process water. Besides
water, the raw IPA stream contains by-products, such as di-isopropyl ether (DIPE)
and isohexenes, and is routed to the distillation section. In the first column, azeotropic
IPA is recovered as overhead. Final dehydration is accomplished in the drying column
by utilizing an entrainer operation and/or a dual-pressure process. The purity of the
obtained chemical grade IPA exceeds 99.9%. For manufacturing “cosmetic grade,” an
additional adsorptive-type purification step is required.
Product utilization: With a global capacity of approximately 2 metric MMk, IPA has
found a wide range of applications. “Chemical grade” is used as an intermediate for
the manufacturing of acetone and other compounds such as ethers, alcoholates,
alkylchlorides and amines. It is further utilized in the production of cellulose lacquers
and serves as a solvent for natural and synthetic resins. Due to its extremely high purity
and its pleasant and fresh odor, “cosmetic grade” IPA is included in many products,
in particular in skin lotions and hair care products. Like ethanol, IPA is an effective
disinfectant that exhibits excellent pharmacological and toxicological properties.
Yields: The average propene conversion per reactor pass is 75% at a selectivity to IPA
above 95%. To achieve a high overall yield, unreacted propene from the reactor offgas
is routed to a re-concentration column prior to being recycled to the reactor.
Utilities: (Per metric ton of chemical grade IPA):
Electricity
135 kWh
LP steam
3,300 kg
Cooling water
54 m³
Process water
1.4 m³
Catalyst life
> 12 mos
DIPE
column Propane to fuel
DIPE
Water
Water
treat
Byproduct
Chemical grade IPA
Installations: Several commercial plants for the production of IPA have been installed
for capacities between 30 kta–200 kta.
Licensor: thyssenkrupp. The former proprietor of this process was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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Olefins—MEK Process
H2
Application: The thyssenkrupp MEK process catalytically dehydrogenates secbutanol (SBA) to produce high-purity methyl ethyl ketone (MEK).
Description: SBA is vaporized and charged to a multi-tube-type reactor that is filled
with a special copper-based catalyst. The dehydrogenation reaction is endothermic,
so a hot oil circulation is established. The reactor temperature is between
240°C–270°C, regarding start-of-run and end-of-run conditions. At this point,
the catalyst will be regenerated in-situ by burning off the coke deposits with air,
and the copper oxide is subsequently reduced with hydrogen.
The reactor effluent is cooled and passed to a separator vessel. The hydrogenrich gas is refrigerated to minimize product losses, recovering hydrogen as valuable
high-purity hydrogen (about 99 mol%). The raw MEK is subsequently dried by
means of an entrainer, and distilled up to 99.7% purity. The MEK column bottoms
contain unconverted SBA and some higher boiling byproducts, which are returned
to the SBA distillation unit for product recovery.
Product Utilization: MEK is mainly utilized as a solvent in paints, lacquers, printing
inks and aluminium foil lacquers. Other applications include solvent extraction
in several industrial sectors (e.g., lube oil, plastics and rubber), the production of
synthetic leather and transparent paper, as well as use as a degreasing agent.
Yields: The conversion of SBA per reactor pass exceeds 80%. By recycling
unconverted SBA, an overall conversion to MEK of 98% is achieved.
Utilities: (Per metric ton of MEK):
Electricity
18 kWh
LP steam
1,700 kg
Cooling water
24 m³
Hot oil
229 kWh
Catalyst life
> 4 years
SBA
Offgas
MEK product
Drying
column
Reactor
Refrigeration
system
MEK
column
H2O
SBA and heavies
to SBA distillation
Crude
ketone
Separator
Installations: Numerous commercial plants for the production of MEK have been
installed for capacities between 3,000 tpy–57,000 tpy.
Licensor: thyssenkrupp. The former proprietor of this process was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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Olefins—MIBK Process
Compressor
Application: The thyssenkrupp MIBK process produces high-purity methyl isobutyl
ketone (MIBK) from acetone and hydrogen. Compared to conventional technology,
this process is a single-stage process applying one bifunctional catalyst only. The
design provides two reactors that are operated in parallel to allow continuous
operation, while the catalyst in one of the two reactors can be regenerated.
Description: Preheated acetone and hydrogen are charged to a tubular-type reactor.
The reaction is catalyzed by a strong acidic, palladium-doped cation exchange resin
and takes place simultaneously (via the formation of an intermediate product) at
a pressure of 30 bar and a temperature between 110°C and 130°C. The overall reaction
is slightly exothermic, and the temperature in the reactor is controlled by means of
a tempered water system.
The selectivity of the process is 90% at mid-of-run conditions. Due to the
strong hydrogenation activity of the catalyst, the formation of higher condensations
products (C9 or C12 components) that cause plugging and deactivation of the catalyst
is prevented.
The raw MIBK from the reactor section is passed to the distillation section, where
unconverted acetone and byproducts are separated. Recovered unconverted acetone
is recycled to the reactor section. The purity of the obtained MIBK product exceeds the
typical MIBK specification of 99.5 wt%, with a water content that is less than 0.1 wt%.
In commercial plants, a purity of more than 99.8 wt% can be achieved.
Product Utilization: MIBK is predominantly utilized as a solvent in resins (vinyl,
epoxy, acrylic and natural resins), nitrocellulose and printing inks. It has also proven to
be a versatile extraction solvent in the production of antibiotics and, in particular, the
removal of paraffins from base oils in the lube oil industry.
Yields: Overall yields in excess of 92% can be achieved, while the conversion per pass
is approximately 30%. Unconverted acetone is returned to the reactors.
Reactor
Acetone column
Acton recycle
MIBK
purification
section
Light
byproducts
MIBK
product
H2
Acetone
Heavies
Crude
ketone
Installations: Several commercial plants for the production of MIBK have been
installed with capacities between 7 kta–30 kta.
Licensor: thyssenkrupp. The former proprietor of this process was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com, dorothe.weimer@thyssenkrupp.com
Utilities: (Per metric ton of chemical grade MIBK):
Electricity
60 kWh
LP steam
3,000 kg
MP steam
1,000 kg
Cooling water
150 m³
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Olefins—Polynaphtha™ and PolyFuel®
Application: Conversion of butene and pentene cuts into high-quality car fuels:
gasoline, diesel, jet A1 and kerosine
Description: In a context of dwindling refinery margins that are limiting capital
investment, refiners are under increased pressure to respond to market volatility
caused by new regulations, widely fluctuating feed prices and unpredictable operating
margins. Axens has developed the Polynahptha and PolyFuel technologies to answer
these challenges.
Polynaphtha and PolyFuel are Axens oligomerization technologies that transform
olefins contained in light cracked cuts into heavier C6+ olefins, at minimum cost.
Polynaphtha can accept a C3–C4 olefinic cut, and PolyFuel can accept a range
of C3–C9 olefinic cut produced downstream of the FCC, steam cracking or coker units.
However, the benefits will be maximized using the C3–C6 olefinic cut (LPG and/or
LCN cut) that is less contaminated than the heavier cut.
Olefins are oligomerized catalytically in fixed-bed reactors in series. Conversion
and selectivity are controlled by reactor temperature adjustment, while the heat
of reaction is simply removed by feed-effluent heat exchange. The reactor section
effluent is fractionated, producing LPG raffinate depleted in olefins, gasoline and
middle distillates fractions. The olefin fractions obtained can be used as high-octane
blending stocks for the gasoline pool, and as high-smoke point blending stocks for
kerosine, jet fuel and diesel fractions. The adjustable product pattern ranges from
100% gasoline to 70% middle distillates.
For greater gasoline production, olefin-rich C4-FCC cut is usually sent to an
alkylation unit to produce alkylate, thus increasing the overall gasoline yield. In most
recent max-gasoline production schemes, alkylation has been advantageously
substituted by Polynaphtha, which delivers high-quality gasoline at a much lower cost.
The Oligomerization technologies display the following advantages: moderate
investment and utilities consumption; continuous operation; regenerable and
environmentally friendly catalyst; easy monitoring by exotherm control; versatile
product range; and good-quality gasoline and distillates.
References:
1. PTQ&A, Petroleum Technology Quarterly, pp. 16, 2Q 2011, March 2011.
2. Gagnière, M., A. Pucci and E. Rousseau, “Tackling the gasoline/middle
distillate imbalance,” Petroleum Technology Quarterly, 2Q 2013.
Licensor: Axens
Website: www.axens.net/our-offer/by-market/oil-refining/bottom-of-the-barrel/
73/oligomerization.html
Contact: www.axens.net/contact.html
Installations: To date, Axens has been awarded with more than 20 references for its
oligomerization technologies (Polynaphtha, PolyFuel, Selectopol™ and FlexEne™), and
several units are now in operation worldwide.
OMV Petrom has selected PolyFuel technology for its project at the Petrobrazi
refinery. The capacity of the project is 200,000 tpy.
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Olefins—SBA Process
Anion
exchanger
Application: Within the thyssenkrupp SBA process, secondary butanol (SBA) is
formed by direct hydration of n-butenes with water in the presence of a strongly
acidic ion exchange resin catalyst. In comparison to sulfuric acid technology, the
direct hydration process forms fewer byproducts (thus requiring less feedstock),
has lower utilities consumption, requires no chemicals (such as nitric and sulfuric acid)
and is environmentally friendly, as it generates no waste. These advantages result
in approximately 25% lower SBA manufacturing costs.
Description: Fresh feed is blended with debutanizer overhead recycle (butane/
butene) and with part of the process water. After preheating to 150°C–170°C,
this mixture is fed to the reactor at a pressure of 50 bar–70 bar, where it passes
upwards through several catalyst beds, entraining the generated SBA.
Make-up demineralized water is added to the circulating water stream. Following
each catalyst bed, water is separated from the organic phase and withdrawn from the
reactor, while process water is introduced to the subsequent beds. In addition to a very
small amount of SBA, the withdrawn water contains ions released from the catalyst.
To remove these components from the circuit, it is passed through an anion exchanger.
The organic effluent phase is cooled against the reactor feed, passed through a
vessel where the water is separated, and admitted to the debutanizer column. The raw
SBA bottoms stream is dry and typically contains less than 0.1% C4 hydrocarbon, some
SBE and TBA, as well as olefin dimers and small amounts of high boiling compounds.
The raw SBA is subsequently distilled to a purity exceeding 99.0%.
The bulk of the debutanizer overhead stream, consisting of butenes and butanes,
is returned to the reactor. Inert butanes that have entered the system with the fresh
feed must be withdrawn from the butene recycle stream.
Yields: The per-pass conversion of butenes is approximately 10%; and an overall
conversion of 90% or higher is accomplished by recycling unconverted butenes.
The selectivity to SBA is between 96%–99%.
Utilities: (Per metric ton of 99.0% SBA):
Electricity
200 kWh
LP steam
3,200 kg
MP steam
1,900 kg
Cooling water
30 m³
Process water
0.3 m³
Catalyst life
15 months
SBA-DH reactor
Debutanizer column
SBA purification column
SBA rerun column
SBA
Heavies
Water
Raw SBE
Feed
Spent butene
Installations: Several plants for the production of SBA/MEK have been installed
with singular capacities from 3,150 tpy–60,000 tpy. More plants have been installed
with a sulfur acid process.
Licensor: thyssenkrupp. The former proprietor of this process was ThyssenKrupp
Uhde GmbH.
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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Olefins—Snamprogetti™
High-Purity Isobutylene (SP-HPIB)
Application: The Snamprogetti metyl tertiary butyl ether (MTBE) cracking
technology (SP-HPIB) produces high-purity isobutylene that can be used as
a monomer for elastomers (polyisobutylene, butyl rubber) synthesis and/or as
an intermediate for the production of chemicals [methyl methacrylate (MMA),
tertiary-butyl phenols, tertiary-butyl amines, etc.].
Light-ends
Ether
MTBE feed
3
4
Feed: MTBE is used as the feedstock in the plant. In case of a high-level of impurities,
a purification section can be added upstream of the reactor.
Description: The SP-HPIB technology is based on proprietary catalyst and a
reactor to carry-out the reaction with excellent flexibility and without corrosion
and environmental problems. With the SP-HPIB consolidated technology, it is
possible to reach the desired isobutylene purity and production with only one
tubular reactor (1) filled with a proprietary catalyst characterized by the right
balance between acidity and activity.
The reaction effluent, consisting mainly of isobutylene, methanol (CH3OH)
and unconverted MTBE, is sent to a counter-current washing tower (2) to separate
out methanol. It then moves to two fractionation towers to separate isobutylene
from unconverted MTBE (3), and is then recycled back to the reactor (4).
The produced isobutylene has a product purity of 99.9+wt%. The CH3OH/water
solution that leaves the washing tower is fed to the alcohol recovery section (5),
where high-quality CH3OH is recovered. The unit can be easily integrated with the
MTBE production unit to treat a C4 stream to produce a high-purity isobutylene
stream. This solution lead to consistent savings in fixed and operating costs.
Advantages: High degree of selectivity; catalyst life that can last more than 2 yr;
constant purity along the catalyst lifecycle; no special requirements on MTBE purity;
maximization in the use of carbon steel; minimization of water use; elimination
of pollution problems.
Economics:
Utilities: (For a standalone unit with high-pressure steam as a heating medium)
Electricity
15 kWh/t isobutylene
Steam, HP, MP and LP
4.4 t/t isobutylene
Water, cooling (rise 10°C)
231 m³/t isobutylene
1
MeOH
2
High-purity
isobutene
5
Development/delivery: Saipem has developed the proprietary catalyst through
recipe identification, control tests, fine-quality control and authorized manufacturer
check and selection.
Installations: Six units have been licensed by Saipem.
Licensor: Saipem S.p.A.
Website: www.saipem.com
Contact: Maura.Brianti@saipem.com
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Olefins—TBA Process
Application: The thyssenkrupp TBA process relates to a process for the production
of tertiary butanol by reacting an isobutylene-containing hydrocarbon stream
with water in the presence of a strongly acidic, solid hydration catalyst.
Description: An isobutylene-containing hydrocarbon mixture is reacted with water in
the presence of a hydration catalyst—a cation exchange resin of the sulfonic acid type,
in particular—in a single reactor containing several reactor beds as separate reaction
zones. After being washed with water, the raffinate stream leaving the reactor is
practically free from alcohol.
Raw TBA with water is fed first to the drying column. Azeotropic TBA that may
contain 0.05%–1% secondary butanol (SBA), a small amount of dimeric compounds
and water (12%) is obtained at the top of the drying column. The azeotropic alcohol
is further treated by the TBA column.
According to a preferred embodiment of the process, the reaction temperatures
in four reactors that are connected in series are increased so that almost complete
conversion of isobutene and a 99%–99.9% selectivity can be established.
Utilities: C4 feed containing 21% isobutene; per metric ton of TBA
Electricity
50
kWh
MP steam
1,200
kg
LP steam
300
kg
Cooling water
32
m³
TBE reactor
C4 feedstock
Wash
column
Drying
column
TBA
column
Water
decanter
Stripper
raffinate 2
Heaviers
Water
Water
plant
TBA product
Installations: Several MTBE units have been converted to TBA production
in the last few decades.
Licensor: thyssenkrupp
Website: www.thyssenkrupp-industrial-solutions.com
Contacts: thomas.streich@thyssenkrupp.com
dorothe.weimer@thyssenkrupp.com
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Oxygen Enrichment—
Claus, oxygen-enriched
Application: Debottleneck existing sulfur recovery units (SRUs) or reduce size, capital
and operating costs for new facilities through the oxygen enrichment of combustion air.
Description: In an air-based Claus plant, nitrogen from the combustion air usually
comprises more than half of the molar flow through the plant, occupying a large part
of the overall installed volumetric capacity. By replacing part of the nitrogen with O2,
the plant’s capacity can be increased significantly. The level of air enrichment with
O2 depends on the level of desired capacity increase:
• Up to about 26% (v) of O2 concentration in the process air, and only
minor modifications to the plant—mainly to the burner—can be expected.
• More than 26% (v) of O2 concentration in the enriched air, but less than
45% (v). The implementation of a special Claus burner is mandatory.
• More than 45% (v) O2 concentration. Special technology must be implemented.
Sulfur recovery efficiency for an O2–based Claus process is slightly better than
that of an air-based Claus process.
Operating conditions: The major difference is the temperature in the Claus reaction
chamber, where the temperature can be as high as 1,500°C.
Yields: Slightly higher than standard Claus while delivering sizable higher capacity.
Advantages: Compared to a standard Claus unit, the smaller unit can treat higher
acid gas flowrates. With a marginal capital investment, the plant’s capacity can
increase up to 200% of the nameplate capacity.
Economics: The investment for a refinery application is related to capacity increase,
and it is generally between 10%–30% of an air-based Claus.
Oxygen
Air
To catalytic
stages
SWS acid gas
HP steam
Thermal reactor
Amine acid gas
LP steam
Sulfur
condenser
WHB
Boiler feedwater
Boiler feedwater
Liquid sulfur
Liquid sulfur
References:
1 “A hot and tricky process environment,” Sulphur, July-August 2007.
2. “Claus plant upgrading with O2 enriched air,” Russian and CIS Refining
Technology Conference, Moscow, Russia, September 23–24, 2010.
Licensor: Siirtec Nigi S.p.A.—Process Department
Website: www.siirtecnigi.com/design-sulphur-recovery-removal
Contact: marketing@siirtecnigi.com
Utilities: As per the standard Claus process, plus pure O2 and a little more cooling
requirements in the tail gas treatment.
Installations: Eight plants licensed. Five are in operation.
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Oxygen enrichment—Claus units
Liquid oxygen tank
Description: As “clean fuels” regulations come into effect, refiners must recover
more sulfur in their Claus plants. As a byproduct of deep desulfurization, NH3 is
generated and typically must be decomposed in the Claus plant. To upgrade the
sulfur recovery units (SRUs) accordingly, oxygen enrichment is an efficient and
low-cost option. Oxygen enrichment can increase sulfur capacity substantially,
and is capable of efficiently decomposing NH3 from sour-water stripper gas.
Oxygen introduction can be done at three levels, depending on the required
capacity increase:
1. Up to approximately 28% oxygen. Oxygen is simply added to the Claus
furnace air, which can raise sulfur capacity by up to 35%.
2. Up to approximately 40% oxygen. The burner of the Claus furnace must be
replaced. Up to 60% additional sulfur capacity can be achieved by this method.
3. Beyond 40% oxygen. This option allows for 100% more capacity and beyond.
Here, major modification of the Claus unit is necessary, e.g., implementing
a second thermal stage.
Oxygen can be sourced from onsite liquid oxygen tanks, vacuum pressure
swing adsorption (VPSA) systems, air separation units (ASUs) or pipeline supply.
Oxygen consumption in Claus plants fluctuates widely in most cases; therefore,
tanks and VPSA are the best choices due to ease of operation, flexibility and
economy. For oxygen addition into the air duct, a number of safety rules must
be observed. Linde’s FLOWTRAIN® oxygen metering device contains all of the
necessary safety features, including flow control, low-temperature and low-pressure
alarm and switch-off, and safe standby operation. All features are connected to
the Claus plants’ process control system.
An efficient mixing device ensures even oxygen distribution in the Claus air.
A proprietary Claus burner was developed specifically for air- and oxygen-enriched
application. This burner provides a short, highly turbulent flame to ensure a robust
approach toward equilibrium for Claus operation and for the decomposition of NH3 .
Advantages:
• Increased Claus plant capacity
• Increased productivity without changing the pressure drop
• More effective treatment of NH3 -containing feeds
• Less effort for tail gas purification (reduced nitrogen flow).
Claus plant process
control system
Vaporizer
Application: Cost-effective debottlenecking, typically for sulfur recovery capacity
increase and/or destruction of hazardous materials, such as ammonia (NH3 ).
Controller
Measuring and
control unit
FLOWTRAIN
1
Steam
2
Onsite ASU
4
Process gas to
catalytic reactors
Air
3
Acid gas plus sour
water stripper gas
Oxygen pipeline
BFW
1 Alternative oxygen sources
2 FLOWTRAIN with all required safety features
3 Oxygen injection and mixing device
4 Claus reaction furnace with burner for air and/or oxygen enriched operation
Economics:
As oxygen enrichment substantially increases Claus plant capacity, it is an
economical alternative to the construction of additional Claus process plants.
Operating costs vary and depend on duration of oxygen usage. Typically, annual
costs of oxygen enrichment are estimated to be 10%–40% of Claus plant operation,
providing the same additional sulfur capacity. Improved NH3 destruction substantially
lessens maintenance, such as cleaning ammonium salts from heat exchanger tubes.
Corrosion is greatly reduced, and plant availability is improved.
References:
1. Kertynski, J. and B. Schreiner, “Increased flexibility of refineries by O2 enrichment,”
World Refining Association Refining & Petrochemical 2015 Budapest Conference,
Budapest, Hungary, October 2015.
Licensor: Linde AG
Website: www.leamericas.com/clauso2
Contact: www.leamericas.com/en/contact/index.html
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Oxygen Enrichment—FCC units
Liquid oxygen tank
Application: Increase feed throughput capacity by up to 50%; provide flexibility
for heavier feeds, load changes and light products; overcome regenerator blower
limitations; reduce catalyst losses.
Description: The increase in heavier feeds contributes to the need for feed
treatment flexibility in fluid catalytic cracking units (FCCUs), and demand for gasoline
contributes to the need for increased throughput. Both goals can be achieved
via oxygen enrichment in the FCC regeneration process.
In the FCC reactor, long-chain hydrocarbons are split into shorter chains in
a fluidized-bed reactor at 450°C–550°C. This reaction produces coke as a byproduct
that deposits on the catalyst. To remove the coke from the catalyst, it is burned off
at 650°C–750°C in the regenerator. The regenerated catalyst is returned to the reactor.
Oxygen enrichment, typically up to 27 vol% oxygen, intensifies catalyst
regeneration and can substantially raise throughput capacity and/or conversion of
the FCCU. Oxygen can be sourced from onsite liquid oxygen tanks, vacuum pressure
swing adsorption (VPSA) systems, air separation units (ASUs) or pipeline supply.
Oxygen consumption in FCCUs fluctuates widely, in most cases, so tanks and VPSA
systems are the best choices due to ease of operation, flexibility and economy.
For oxygen addition into the air duct, a number of safety rules must be observed.
The FLOWTRAIN® oxygen metering device contains all necessary safety features,
including flow control, low-temperature and low-pressure alarm and switch-off, and
safe standby operation. These features are connected to the FCCU’s process control
system. An efficient mixing device, OXYMIX™, ensures even oxygen distribution in
the air feed to the FCC regenerator.
Advantages:
• Increases plant capacity
• Provides more feedstock flexibility, especially heavier feedstocks with
a higher tendency to form coke
• Improves conversion ratio and gasoline yield
• Overcomes air blower constraints
• Reduces carbon monoxide (CO) in regenerator off-gas, produces less
nitrogen oxide (NOx )
• Decreases catalyst abrasion and erosion of cyclones due to reduced
gas flow, resulting in fewer repairs and less downtime.
Economics: Oxygen enrichment in FCC regeneration is economically favorable in many
plants. For example, one refinery increased throughput by 15%. The net improvement
Off-gas
Vaporizer
Steam
Crack gas
7
Steam
2
1
Gasoline
5
8
3
6
Gas oil
Residue
Onsite ASU
Air
9
4
Oxygen pipeline
Vacuum gas
1 Alternative oxygen sources
2 Process control system for FCC unit
3 FLOWTRAIN for dosing oxygen with all
required safety features
4 Oxygen injection and mixing device
Cycle oil
5 FCC reactor
6 Regenerator
7 Steam boiler
8 Fractionator
9 Cycle oil separator
was a 26% increase in higher-value products, such as naphtha. Likewise, lower-value
products increased only 5%, such as fuel gas. The net profit increased substantially.
Operating costs will depend on the cost for oxygen and the duration of oxygen
enrichment. Economics of oxygen usage can be calculated on a case-by-case basis
and should include increased yields of higher-value products and the optional
usage of lower-value feeds.
References:
1. Kertynski, J. and B. Schreiner, “Increased flexibility of refineries by O2 enrichment,”
World Refining Association Refining & Petrochemical 2015
Budapest Conference, Budapest, Hungary, October 2015.
Licensor: Linde AG
Website: www.leamericas.com/fcco2
Contact: www.leamericas.com/en/contact
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Treating, Gas/Liquid—AMINEX™
and AMINEX™ COS
Application: Remove acid gas and carbonyl sulfide compounds from LPG-type
and gas streams.
Description: AMINEX and AMINEX COS technologies employ the FIBER FILM®
Contactor as the mass-transfer device, and utilize an appropriate amine as
the treating reagent.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced CAPEX
and less plant space requirements compared to most treating alternatives.
These benefits makes AMINEX and AMINEX COS the technologies of choice.
Installations: AMINEX technologies were first licensed in 1998, and Merichem
has granted 27 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/aminex
Contact: www.merichem.com/company/contact-us
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Aquafining™
Application: Remove soluble organic and inorganic impurities from liquid
and gas hydrocarbon streams.
Description: AQUAFINING technology employs the FIBER FILM® Contactor
as the mass transfer device, and utilizes water as the treating reagent.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced capital
expenditure and requires less plant space compared to most treating alternatives,
making AQUAFINING the technology of choice.
Installations: AQUAFINING technology was first licensed in 1978, and Merichem
has granted 90 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/aquafining
Contact: www.merichem.com/company/contact-us
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Treating, Gas/Liquid—
BELCO® EDV® Wet Scrubbing
Cleaned gas
Stack
Application: BELCO EDV Wet Scrubbing is the global standard for controlling refinery
flue gas emissions [particulate, sulfur oxides (SOx ) and nitrogen oxides (NOx )]
from refinery FCCUs, fluid cokers, fired heaters and boilers. Using a unique
open-vessel design and special non-plugging features, this proven emissions control
technology supports 4 to 7 years of uninterrupted operation, allowing refiners to
concentrate on production rather than emissions control and compliance.
Description: EDV Wet Scrubbing controls all emissions in a single upflow tower,
eliminating the need for separate devices to individually control different emissions.
The process uses water buffered with a reagent to cool, wash and clean flue gas in
a staged approach that minimizes flue gas pressure drop. Hot flue gas is cooled to
saturation with intense liquid sprays in the quench section of an open upflow spray
tower. Liquid sprays in the absorber section remove sulfur dioxide (SO2 ) and NOx ,
as well as particulate, including H2SO4 mist. A patented process oxidizes NOx
compounds to support absorption with liquid sprays. A polishing stage uses
filtering modules to remove additional particulate. A unique condensation/
agglomeration process enlarges and then removes particulate with intense
liquid sprays. Finally, droplet separators ensure a droplet free exhaust. BELCO
EDV Wet Scrubbing can be used with a variety of reagents.
Advantages:
• Particulate, SOx and NOx emissions controlled in a single upflow tower
• High collection efficiency with minimal flue gas pressure drop
• Supports 4 to 7 years of FCCU operation with uninterrupted emissions control
• Handles severe upset conditions, including high particulate carryover
and high-temperature excursions
• High gas flow turndown capability
• Flexibility to use different buffering reagents, including regenerative SO2
processes and once-thru seawater.
Economics: BELCO EDV Wet Scrubbing is successful as a cost-effective and reliable
emissions control solution for critical refinery processes, such as the FCCU.
Droplet
separators
Filtering
modules
Reagent addition
Absorber
Flue gas
Quench
Slipstream to purge treatment unit
Recirculation
pumps
Installations: More than 140 licensed systems worldwide on refinery FCCUs.
Additional systems are on refinery fluid cokers, fired heaters and boilers.
References:
1. “Enhancing the reductions of flue gas emissions from refinery fluid catalytic
cracking units (FCCUs),” 20th Refinery Technology Meet (RTM), India,
February 2016.
Licensor: DuPont Clean Technologies
Website: www.dupont.com/products-and-services/clean-technologies/products/
belco-clean-air.html
Contact: bioscience.dupont.com/clean-technologies-contact
Utilities: Typical utilities include process water, reagent (typical NaOH solution)
and electrical power.
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Treating, Gas/Liquid—
BenzOUT™ technology
Light reformate
Olefins
LPG
Application: ExxonMobil’s cost-effective process for increasing octane,
while reducing benzene in gasoline streams.
Description: BenzOUT technology is a commercially-proven process for octane
increase and benzene reduction in gasoline. The BenzOUT process converts benzene,
typically in a light reformate stream, to higher alkylaromatic blending components
by reacting a benzene-rich stream with light olefins, such as a refinery-grade
propylene stream.
Advantages: BenzOUT technological advantages include:
• Higher quality: A full reformate octane increase of 2–5 points
• Low operating cost
° Low-temperature, liquid-phase process
° No hydrogen (H2 ) consumption
° Simple, fixed-bed reactor
• Higher yields
° > 95% conversion of reformate stream benzene
° Gasoline volume swell.
References:
• Thom, T., R. Birkhoff, E. Moy and E-M, El-Malki, “Consider advanced technology
to remove benzene from gasoline blending pool,” Hydrocarbon Processing,
February 2013.
• Moy, E. and C. Sean, “BenzOUT technology for benzene reduction in gasoline,”
Smyth Handbook of Refinery Processes, McGraw-Hill Education, 4th Ed., 2016.
Reformate or
benzene-rich steam
Stabilizer
Reformate
splitter
BenzOUT reaction
Heavy reformate
Mogas
Licensor: Badger Licensing LLC.
Website: www.badgerlicensing.com/TechServices_Refining_Benzout.html
Contact: info@badgerlicensing.com
Installations: Typically, BenzOUT services include consultation from design through
the startup phases of project implementation and beyond.
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COMPANY INDEX
Treating, Gas/Liquid—
Diesel Upgrading
Hydrogen makeup
Application: Topsoe’s Diesel Upgrading process can be applied for improvement
of a variety of diesel properties, including the reduction of diesel specific gravity,
reduction of T90 and T95 distillation (back-end-shift), reduction of aromatics, and
improvements of cetane, cold-flow properties, (pour point, clouds point, viscosity
and CFPP) and diesel color reduction (poly shift). Feeds can range from blends of
straight-run and cracked gas oils up to heavy distillates, including light vacuum gasoil.
Description: Topsoe’s Diesel Upgrading process is a combination of treating and
upgrading. The technology combines state-of-the-art reactor internals, engineering
expertise in quality design, high-activity treating catalyst and proprietary diesel
upgrading catalyst. Every unit is individually designed to improve the diesel
property that requires upgrading. This is done by selecting the optimum processing
parameters, including unit pressure and LHSV and determining the appropriate
Topsoe high-activity catalysts and plant layout. The process is suitable for new
units or revamps of existing hydrotreating units. In the reactor system, the treating
section uses Topsoe’s high-activity CoMo or NiMo catalyst, such as TK-578 BRIM®
or TK-611 HyBRIM™, to remove feed impurities such as sulfur and nitrogen. These
compounds limit the downstream upgrading catalyst performance, and the purified
stream is treated in the downstream upgrading reactor. Reactor catalyst used in
the application is dependent on the specific diesel property that requires upgrading.
Reactor section is followed by separation and stripping/fractionation where final
products are produced. Like the conventional Topsoe hydrotreating process, the
diesel upgrading process uses Topsoe’s graded-bed loading and high-efficiency
patented reactor internals to provide optimal reactor performance and catalyst
utilization. Topsoe’s high-efficiency internals are effective for a wide range of liquid
loading. Topsoe’s graded-bed technology and the use of shape-optimized inert
topping material and catalyst minimize the pressure drop build-up, thereby reducing
catalyst skimming requirements and ensuring long catalyst cycle lengths.
Furnace
Recycle gas
compressor
Upgrading
reactor
Treating
reactor
Lean amine
Absorber
Rich amine
H2 rich gas
Fresh feed
Production
fractionation
High pressure
separator
Low pressure
separator
References:
1. Patel, R., “How are refiners meeting the ultra-low-sulfur diesel challenge?”
NPRA Annual Meeting, San Antonio, March 2003.
2. Fuente, E., P. Christensen, and M. Johansen, “Options for meeting EU year 2005
fuels specifications,” 4th ERTC, November 1999.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: Topsoe.com
Contact: mkj@topsoe.com
Installations: A total of 22 units; six in Asia-Pacific region, one in the Middle East,
two in Europe and nine HDS/HDA units (see Hydrodearomatization).
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Treating, Gas/Liquid—DynaWave®
Wet Gas Scrubbers
Application: DynaWave wet gas scrubbing technology provides for particulate removal,
hot gas quenching and acid absorption in a single vessel. It guarantees sulfur dioxide
(SO2 ) removal and compliance with air emissions regulations in refinery sulfur recovery
units (SRUs). DynaWave® scrubbers provide the flexibility to bypass the SRU or SRU
tail gas system and maintain plant operation during maintenance and repairs of those
upstream units.
Description: The DynaWave reverse jet scrubber is an open duct in which scrubbing
liquid is injected through a non-restrictive reverse jet nozzle, counter-current to the dirty
inlet gas. Gas enters at the top of the vessel and travels down the inlet barrel, whereas
liquid is sprayed upward into the barrel counter to the gas flow. The gas collides with
the liquid to create a turbulent zone (the froth zone), where the gas/liquid interface is
continuously and rapidly renewed. When the momentum of the gas and liquid balances,
the liquid reverses direction and then falls to the base of the vessel. The clean, watersaturated gas continues through the scrubber vessel to mist removal devices. The liquid
in the vessel sump is recycled to the reverse jet nozzle.
For SRU applications, the DynaWave scrubber is installed after the incinerator and
waste heat boiler, and before the stack.
Operating conditions: Flowrates range from 1,000 Nm3/hr to more than 2,000,000
Nm3/hr, with SO2 levels up to 200,000 ppm. DynaWave® scrubbers can handle inlet
temperatures of up to 2,200°F (1,200°C).
Yields: The liquid is fully oxidized inside the DynaWave vessel, and a small effluent
stream, based on density control, is sent to the wastewater treatment plant.
Advantages: DynaWave scrubbers offer numerous benefits over conventional wet gas
scrubbers:
• Guaranteed low-SO2 outlet from the stack at all times
• Ability to bypass SRU and/or SRU tail gas system and still guarantee
low SO2 outlet at the stack
• High onstream reliability
• Simple operation, low maintenance and little operator attention required
• Virtually unpluggable, with large, open-bore liquid injectors
and nonrestrictive, open vessels
• Small footprint.
Investment: Low CAPEX investment for ultimate air pollution control reliability.
Utilities: Caustic (or other reagent) and makeup water.
Installations: More than 500 wet scrubbing systems are presently installed worldwide.
Licensor: DuPont Clean Technologies
Website: www.dupont.com/products-and-services/clean-technologies/products/
mecs-sulfuric-acid-environmental-technologies/sub-products/dynawave.html
Contact: bioscience.dupont.com/clean-technologies-contact
Copyright © 2017 Gulf Publishing Company. All rights reserved.
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COMPANY INDEX
Treating, Gas/Liquid—
FLEXSORB™ technology
Application: ExxonMobil has developed and commercialized a suite of gas treating
technologies and absorbents, known broadly as FLEXSORB. The FLEXSORB SE
technology is designed for the selective removal of hydrogen sulfide (H2S) in the
presence of carbon dioxide (CO2 ), and utilizes proprietary, severely-sterically hindered
amines. This process allows FLEXSORB SE solvent to achieve high H2S cleanup
selectively at low solvent circulation rates.
ExxonMobil’s FLEXSORB SE and SE Plus solvents are used in a variety of gas
treating applications, including acid gas removal (AGR), acid gas enrichment (AGE)
and tail-gas cleanup units (TGCU). FLEXSORB technology easily fits into natural gas
processing (including onshore and offshore), refining and petrochemical operations
using standard gas treating equipment.
Description: The FLEXSORB technology utilizes equipment that is typical in
amine-type tail-gas treating units. It also incorporates features based on ExxonMobil’s
extensive experience designing and operating gas treating units in all segments
of the energy industry.
A simplified technology process flow diagram (PFD) is shown. The feed gas is
contacted counter-currently with lean FLEXSORB SE solution in the absorber tower
(1). The rich FLEXSORB SE solution is heated in the rich/lean heat exchanger and
fed to the regenerator (2). In the regeneration tower, the acid gas (H2S and CO2 ) is
stripped from the FLEXSORB SE solution by counter-current contacting, with steam
generated in the reboiler. The gas exiting the stripping section of the regenerator
tower is then washed in the reflux (rectifying) section, which is located at the top
of the tower. The acid gas is recycled back to the front of the sulfur recovery unit
(SRU). From the reboiler, the hot/lean FLEXSORB SE solution is sent back through
the rich/lean heat exchanger and further cooled in the lean cooler. Typically,
FLEXSORB services include consultation from design through the startup phases
of project implementation and beyond.
Advantages: FLEXSORB technological advantages include:
• Lower operating costs
° Lower recirculation rates and energy
° Lower corrosion
° Uses conventional equipment and simple to operate
Overhead Acid gas to sulfur
condenser recovery unit
Treated gas
Water
wash pump
Lean
solution
filter
Water
makeup
Feed gas
Fines
filter
Reflux
drum
Purge
Lean surge
vessel or tank
Carbon
treater
Absorber
Rich amine
pump
Lean
cooler
Lean amine
pump
Sump filter
Regenerator
Reflux
drum
Rich/lean
exchanger
Steam condensate
Solvent sump
• Lower capital costs
° Reduced regeneration tower diameter due to lower vapor and liquid loads
° Uses standard gas treating equipment.
Economics: The FLEXSORB SE process has been shown to be a highly-selective
and cost-effective amine solvent process. It is reliable, robust and simple to operate.
Operating experience has shown low corrosion and lower foaming than with
conventional amines. Corrosion is low even at high-rich loadings or high levels of
heat stable salts. Conventional equipment that is used for other amine solvents,
such as countercurrent towers, is also used for the FLEXSORB SE process.
In sulfur plant tail-gas treating unit (TGTU) applications, FLEXSORB SE
solvents can use about half of the circulation rate and regeneration energy
typically required by MDEA-based solvents. CO2 rejection in TGTU applications
is very high, typically above 90%. FLEXSORB SE provides a reduced vapor and
liquid load to the regenerator tower, resulting in a smaller tower diameter compared
with competing technologies.
Continued 
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—FLEXSORB™ technology (cont.)
Installations: The technology and absorbents have been widely applied in more
than 100 commercial applications in petroleum refining, natural gas production
and petrochemical operations.
More than 100 commercial applications have repeatedly demonstrated the
advantages of FLEXSORB SE and SE Plus over competing solvents since the first
commercial unit was started in 1983. Commercial applications include ExxonMobil
affiliates, as well as numerous licensee applications in locations around the world.
References:
1. “Optimum TGT and AGE design and performance,” Hydrocarbon Processing,
Sulfur Solutions 2010.
Licensor: ExxonMobil Catalysts & Licensing LLC
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
2017 REFINING PROCESSES HANDBOOK
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Treating, Gas/Liquid—Gas treating
Treated gas
Application: The Shell portfolio of gas and liquid treating technologies is designed
to remove sour and organic sulfur contaminants encountered in refineries and
liquefied natural gas (LNG), gasification and natural gas production facilities. They are
suitable for treating natural gas, synthesis gas, liquefied hydrocarbons, (e.g., liquefied
petroleum gas (LPG) and Claus plants off-gas). These process technologies help
plants to adhere to tighter product specifications, increase operating capacity and
reduce energy consumption and carbon footprints.
Description: Shell’s ADIP® process is suitable for removing hydrogen sulfide (H2S),
carbon dioxide (CO2 ) and carbonyl sulfide (COS) from hydrocarbon gas and liquid
streams. It is a regenerable aqueous amine process that utilizes alkanolamines
such as diisopropanolamine and methyl diethanolamine. Three processes are offered
for the refinery sector:
• ADIP-D for removing H2S from gaseous streams and H2S/COS
from liquid streams (e.g., LPG).
• ADIP-M, which selectively removes H2S and limits CO2 removal.
It is typically applied in Claus sulfur recovery tail gas treating units,
such as Shell’s Claus off-gas treating (SCOT®) units.
• ADIP ULTRA for removing H2S, and/or CO2 , and/or COS from gases.
This improvement on the Shell ADIP-X process offers reduced circulation
rates, shorter columns and lower regeneration energy requirements.
These improvements substantially reduce CAPEX for greenfield units
and increase capacity and capability for brownfield units.
An ADIP process lineup can be very diverse, depending on the optimization
requirements of the project or site, where multiple absorbers are frequently linked
to a common regenerator. A simplified flow scheme for a high-pressure gas treating
unit consisting of a single absorber column, a hydrocarbon flash vessel and a solvent
regeneration system is shown.
Shell has extensive experience in other, more advanced lineups, including:
• Split-flow—reduced energy consumption, smaller regeneration section
• Semi-lean cascaded flow—reduced energy consumption,
smaller regeneration section
• Super-lean solvent (Super SCOT)—deeper treated gas specification,
reduced energy consumption
• Heated flash (improved enrichment)—improved acid gas quality
• Intercooler—improved selectivity, maximized rich loading.
Acid gas
Treated gas
knockout drum
Absorber
column
Condenser
Reflux
drum
Lean solvent
Lean solvent
cooler
Filter
Feed gas
Flash gas
Regenerator
column
Reboiler
Rich gas
knockout
drum
Rich solvent
Hydrocarbons
flash vessel
Lean rich
heat
exchanger
Lean solvent
The Shell Sulfinol processes (Sulfinol-M and Sulfinol-X) are regenerative, hybridamine processes suitable for bulk and deep removal of H2S, CO2 , COS, mercaptans
and organic sulfides from refinery gases, natural gas, synthesis gas, etc. CO2 can
either be removed or slipped. Two processes are offered:
• Sulfinol-M for selective H2S removal or for bulk H2S and CO2 removal
• Sulfinol-X (typically replacing older Sulfinol-D applications) for bulk
or deep removal of CO2 , H2S and COS.
For both processes, deep removal of mercaptans and COS is possible,
depending on the operating conditions.
The Sulfinol-M and Sulfinol-X processes use a hybrid solution of the tertiary
amine methyl di-ethanolamine and sulfolane. Sulfinol-X contains a piperazine additive
as a process accelerator. The solvent formulations can be tailored for a customer’s
requirements. Neither process forms oxazolidinones, so the need to remove these
components by reclamation is eliminated.
Continued 
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Treating, Gas/Liquid—Gas treating (cont.)
The process lineup is very similar to that of other amine processes, such as the
ADIP process, where the same range of Shell advanced lineups can be applied.
Operating conditions: As with most amine-based gas treating systems, the ADIP
and Sulfinol processes can be adapted to sour gas and liquid streams with varying
levels of contaminants (H2S, CO2 , COS, mercaptans and organic sulfides) down
to extremely low levels.
Treating performance is typically controlled by changing the solvent circulation
and the lean solvent temperature, and by adjusting the regeneration medium input
(low-pressure steam, thermal fluid).
Temperature, °C
Pressure, barg
Absorption
5–60
~0–190
Regeneration
100–130
~0.5–1.5
Plants for ADIP and Sulfinol processes have been built for a wide range of
contaminant concentrations, in climates from desert to arctic and with wide-flexibility
in feed gas pressure and temperature, and solvent temperature. Specifications
down to 1 ppmv for H2S and 50 ppmv for CO2 can be achieved. In certain cases,
lower specifications for H2S and CO2 removal can be guaranteed (e.g., COS removal
rates of 99% and less than 5 ppmv total sulfur can be achieved with Sulfinol-X).
Product Specifications: For a typical feed, see the Application section.
For multiple feeds:
Treated gas
H2S, ppmv
CO2, ppmv
Mercaptans*, ppmv
COS*, mg S/Nm3
Total sulfur*, mg S/Nm3
Treated LPG
H2S, ppmw S
COS, ppmw S
Specification
<1
< 50
<5
<5
< 20
< 10
<5
*Sulfinol
Advantages:
ADIP processes:
• Low degradation solvents, no solvent reclamation required
• Higher solvent loading capacity and smaller equipment required compared
with general amine processes
• Removal of COS from LPG (ADIP-D) without increasing the overall solvent rates
• Highly-selective designs to minimize CO2 recycle to Claus sulfur recovery units
(ADIP-M).
Sulfinol processes:
• Treating highly contaminated gases to very low-sulfur specifications is
possible
• Additional downstream polishing units can be avoided for natural gas liquid
plants
• Solvent reclamation is not required
• Low-solvent foaming tendency
• Sulfinol-M is highly selective compared with traditional amines, so it can also
be used in tail gas treating (SCOT) applications
• Sulfinol-X can be used to achieve low CO2 specifications for LNG applications
(50 ppmv)
• Sulfinol-X has a higher solvent loading capacity and lower specific energy
consumption compared with the first-generation Sulfinol-D process, so it is an
excellent choice for debottlenecking existing Sulfinol-D units.
Development/Delivery: Shell Global Solutions offers a suite of technologies for
treating contaminated feed streams before they reach downstream processes to help
meet the most stringent environmental requirements and product specifications, even
in the harshest fluctuating operating conditions.
Shell is both an operator and licensor, which leads to optimized design margins
and applied lessons:
• More than 60 yr of licensing experience
• More than 100 yr of operational experience
• In-house-developed processes.
All of this leads to a continuing cycle of development that brings additional value
to Shell and its partners. For example, the new (2017) ADIP ULTRA process results in a
sharper design that offers:
• Up to a 25% increase in CO2 removal capacity
• Up to a 30% reduction in regeneration energy
• Up to a 30% reduction in equipment costs, thereby increasing project net
present value
Continued 
2017 REFINING PROCESSES HANDBOOK
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Treating, Gas/Liquid—Gas treating (cont.)
• Reduced circulation rates
• Increased throughput
• The ability to handle more challenging gas.
Installations: ADIP technology was first developed in the 1950s. With more than
500 Shell operating facilities and licensees, it is our most referenced technology
to date. ADIP technology has established a track record of high levels of performance
and reliability.
Sulfinol technology has been around since 1964. More than 250 Sulfinol units
have gone into operation or are under construction worldwide in refineries and
natural gas, LNG and chemical plants.
References:
1. Chilukuri, P., G. Bowerbank and A. Bhattacharya, “Understanding the impact of
hydrocarbon co-absorption losses on revenues from your gas plants: The reality
through lifecycle costs analysis,” Gas Processing, March/April 2016.
2. Bowerbank, G., “Smart design for high CO2 removal for natural gas production,”
Gas Processing, November/December 2015.
3. Ritchie, D., “Shell licensed technology helps Pertamina EP treat complex gas
project,” Petrominer, April 2013.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
2017 REFINING PROCESSES HANDBOOK
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Treating, Gas/Liquid—LO-CAT®
H2S Removal Technology
Application: An environmentally-friendly way to remove hydrogen sulfide (H2S)
from natural gas.
Description: The LO-CAT process is a patented, wet-scrubbing, liquid redox system
that uses a chelated iron solution to convert H2S to innocuous, elemental sulfur.
It does not use any toxic chemicals, and does not produce any hazardous waste
byproducts. The catalyst is readily available and it is continuously regenerated
in the process. Since less catalyst is used, more money is saved.
The LO-CAT process is applicable to all types of gas streams including air,
natural gas, carbon dioxide (CO2 ), amine acid gas, biogas, landfill gas, refinery fuel
gas, etc. The liquid catalyst adapts easily to variations in flow and concentration.
Flexible operation allows 100% turndown in gas flow and H2S concentrations.
Units require minimal operator attention.
Advantages: The LO-CAT process is reliable, efficient and economical, and is licensed
with guarantees of H2S removal efficiency, sulfur removal capacity and chemical
consumption rates.
Installations: More than 200 installations around the world depend on the LO-CAT
process to remove H2S from gas streams.
Licensor: Merichem
Website: www.merichem.com/gas/upstream/natural-gas/lo-cat
Contact: www.merichem.com/company/contact-us
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Treating, Gas/Liquid—
LPG Sweetening—Sulfrex™
Application: Process to extract and convert mercaptans in hydrocarbons into LPG,
light naphtha.
Description: Mercaptans (RSH) occur naturally in crude oils, but are also generated
from other sulfur compounds during crude fractionation and cracking processes.
Mercaptans are undesirable in gasoline due to their obnoxious odor and their
tendency to hydrolyze, forming toxic and corrosive hydrogen sulfide. The classic tests
for mercaptan presence are the “doctor” test and odor threshold.
Axens’ Sulfrex and sweetening processes eliminate mercaptans by extraction
or by their conversion into less aggressive compounds, thus protecting downstream
equipment or units such as hydrotreaters, as well as meeting fuel specifications.
The extractive Sulfrex process both sweetens and reduces the total sulfur
concentration. With its moderate operating conditions of pressure and ambient
temperature, this continuous process is ideal for C3 , C4 , LPG, light gasoline and NGL
feeds.
The overall reaction is shown here, where R represents an aliphatic group. The
process involves two steps, starting with extraction and culminating in oxidation:
Overall Sulfrex reaction
4 RSH + O2 → 2 RSSR + 2 H2O
First step: Extraction
RSH + NaOH → NaSR + H2O
Second step: Oxidation
4 NaSR + 2 H2O + O2 → 4 NaOH + 2 RSSR
Aqueous phase
Hydrocarbon phase
Feed
Optional caustic
prewash
Extractor
Oxidizer
Separator
Catalyst
tank
Coalescer
Disulfides
Feed
Steam/CW
CW
Makeup
caustic
Spent
caustic
Installations: Axens has licensed more than 40 grassroots Sulfrex units.
Licensor: Axens
Website: www.axens.net/product/process-licensing/10072/sulfrex.html
Contact: www.axens.net/contact.html
In the flow diagram, the light mercaptans are extracted (extractor) by a weak
caustic solution, forming water and sodium mercaptide salts (NaSR). These salts are
oxidized (oxidizer) by air injection in the presence of the LCPS 30 catalyst, producing
an organic disulfide (RSSR) phase that separates by gravity (separator) from the
aqueous solution. This phase is sent to storage or further treatment facilities. The
resulting regenerated caustic solution is then returned to the extractor. The product
flows through a sand filter to eliminate traces of free water and caustic.
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Treating, Gas/Liquid—MECS®
SolvR® Technology
Application: Applications include single absorption sulfuric acid (H2SO4) plant tail
gas, Claus SRU tail gas sulfur dioxide (SO2 ) recovery/recycle, and other applications
where SO2 cannot be directly recovered as sulfur or H2SO4. The recovered SO2 can be
liquefied, converted into H2SO4 or converted into sulfur.
Description: The MECS SolvR technology employs absorption as the means of
removing SO2 from the hot tail gas feed. For water balance purposes, the tail gas is
saturated with water and cooled before entering the bottom of an absorber tower.
Lean solvent enters at the top of the absorber tower in a counter-current fashion. SO2
absorbs into the solvent, yielding a clean gas to the stack and an SO2 -rich solvent
from the bottom of the absorber tower. The SO2 -rich solvent stream is stripped of
SO2 using steam in the stripper tower, then cooled and returned to the absorber as
lean solvent. The water saturated SO2 -rich gas from the stripper tower is routed to the
water column for concentrating the SO2 and purifying the water.
In some cases, the SO2 -rich feed gas to the SolvR plant may need additional
conditioning and cooling prior to entering the absorber tower. In these cases, a
DynaWave® reverse jet scrubber can be installed upstream of the SolvR plant.
Advantages: MECS SolvR technology uses a readily available, lower-cost solvent that
is ecofriendly and does not react with H2SO4. Instead, sodium ions in the solvent react
with H2SO4 to form aqueous sodium sulfate (Na2SO4 ), which is readily separated from
the solvent. Advantages of the MECS SolvR process include:
• Guaranteed SO2 emissions at 20 ppmv or less
• Low operating costs due to low steam usage and low-cost, readily-available
solvent
• Simple, reliable operation over a wide range of SO2 concentrations.
References:
1. Castaneda, V., S. Puricelli, et al., “Commercialization of MECS’ SolvR™
Regenerative SO2 Technology,” SYMPHOS 2015, Marrakesh, Morocco,
May 18–20, 2015.
Website: www.dupont.com/products-and-services/clean-technologies/products/
mecs-sulfuric-acid-environmental-technologies.html
Contact: bioscience.dupont.com/clean-technologies-contact
Licensor: DuPont Clean Technologies
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—MECS®
Spent Acid Recovery (SAR)
Application: Spent acid and/or hydrogen sulfide (H2S) is thermally oxidized and
decomposed into primary constituents, which are subsequently converted into highpurity (99.2 wt%) sulfuric acid through a series of reaction and absorption steps. The
primary application described here is for the recovery of spent acid from a sulfuric
acid alkylation unit.
Description: In the case of spent acid, fuel is burned with the spent acid in the
decomposition furnace to achieve the required decomposition temperature. The
hot sulfur dioxide (SO2 ) combustion gas is then cooled in a waste heat boiler, where
energy is recovered as high-pressure superheated steam. The cooled SO2 process gas
then enters the primary MECS DynaWave® reverse jet scrubber. The MECS DynaWave
scrubber removes solid particulate from the process gas stream. From the scrubber
on, the process equipment arrangement will have some variation, depending on the
amount of insoluble material generated in the combustion chamber.
Following the DynaWave gas cleaning train, the process gas is dried and then
flows to the main gas blower, which provides the motive force for moving process gas
through the unit. The gas flows through three passes of catalyst with inter-cooling
between each pass of catalyst. The proprietary MECS catalyst promotes the reaction
of SO2 and oxygen (O2 ) to sulfur trioxide (SO3 ). The converted process gas then
passes through a strong sulfuric acid absorbing tower, where the SO3 in the process
gas is absorbed into the strong acid and reacts with free water to produce 99.2 wt%
sulfuric acid (H2SO4 ). Process gas from the absorbing tower overhead flows to the
SolvR® regenerative scrubbing system, where the SO2 is concentrated. Concentrated
SO2 from the SolvR system is recycled back to the front of the SAR unit for conversion
and absorption.
Advantages: The advantages of the MECS SAR process include:
• Highest acid concentration (99.2 wt% H2SO4 ) of all SAR processes,
which increases alkylate quality and reduces acid consumption
• Higher onstream time compared to wet gas processes, achievable due to
the online cleaning of the waste heat boiler and the efficient removal
of process gas with the DynaWave scrubber
• Best-in-class SO2 and acid mist abatement technology, with commercial
units demonstrating nearly undetectable emissions levels
• 25% of the MECS SAR unit is modularized, decreasing the total installed cost
of the unit.
Primarry
Dynawave
reverse jet
scrubber
Dynawave
gas cooling
tower
scrubber
Decomposition
furnace
Spent acid
Acid gas
Fuel gas
Waste heat boiler
Absorbing
tower
Air
Superheater
COLD MonplexTM
SO2→SO3
Main gas blower
HOT
Monplex
Drying
tower
SO2→SO3
SO2→SO3
Steam
SolvR
Economizer Super
heater
Converter
Installations: DuPont is the world’s leading supplier of sulfuric acid technology,
with more than 1,000 sulfuric acid plants around the world across all applications,
and more than 60 units operating in alkylation or chemical SAR applications.
Licensor: DuPont Clean Technologies
Website: www.dupont.com/products-and-services/clean-technologies/products/
mecs-sulfuric-acid-environmental-technologies/sub-products/spent-sulfuric-acid.html
Contact: bioscience.dupont.com/clean-technologies-contact
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—
MECS® SULFOX™ Process
Converter with internal
heat exchangers
>390°C
Application: The SULFOX process is a highly energy efficient technology that
produces saleable sulfuric acid (H2SO4 ) as the product from cleaning waste gases
containing sulfur compounds. Applications for the SULFOX process include refinery
and natural gas processing, sulfur recovery units (SRUs), coke manufacturing, and
spent acid and liquid sulfates regeneration.
Description: The SULFOX process is based on the thermal and catalytic conversion
of sulfur-bearing compounds into H2SO4 . Depending on the feed gas conditions,
customized plant types are offered.
For low concentrations, the feed gas is preheated to the required catalyst inlet
temperature by the glass tube heat exchanger of the condensation column and an
additional gas preheater from the heat recovery system. An additional direct fired
preheater is used for startup and very low-plant rate operation. For high-concentration
hydrogen sulfide (H2S), the gas feed is burned in a combustion chamber and cooled
by steam equipment to the required catalyst inlet temperature. The converter contains
catalyst beds where the sulfur compounds are oxidized to sulfur dioxide (SO2 ) and
sulfur trioxide (SO3 ). The SO3 reacts with the water vapor to form gaseous H2SO4 .
The acid condenses in the condensation column and evaporation of water produces
concentrated acid that is collected in the sump of the column. Brink® mist eliminators
or a wet electrostatic mist precipitator (WESP) remove the remaining acid mist. A heat
recovery system transfers the excess heat to either the incoming feed gas stream or
high-pressure steam produced in the steam equipment.
Condensation column
with glass heat exchanger
SO2→SO3
70°C
WESP
SO2→SO3
SO2→SO3
Heat recovery
(steam, BFW,
molten salt)
~260°C
Recovered
acid mist
Licensor: DuPont Clean Technologies
Website: www.dupont.com/products-and-services/clean-technologies/products/
mecs-sulfuric-acid-environmental-technologies/sub-products/mecs-sulfox.html
Contact: bioscience.dupont.com/clean-technologies-contact
Advantages: Advantages of the MECS SULFOX process include:
• Low SO2 and acid mist emissions
• Very reliable and proven gas cleaning using DynaWave® technology
• Simple, automated operation (minimal operators required)
• Robust and low-maintenance acid condensation column with short horizontal
glass tubes
• Special catalyst usage for specific applications
• Long catalyst operation without screening
• Compact, modular design.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Mericat™ II
Application: Removes hydrogen sulfide (H2S) and sweetened mercaptan
compounds in jet fuel, kerosine and gasoline/naphtha streams.
Description: MERICAT II technology employs the FIBER FILM® Contactor as the
mass-transfer device, and utilizes a caustic/catalyst/air mixture as the treating reagent.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced CAPEX
and requires less plant space compared to most treating alternatives. These benefits
make MERICAT II the technology-of-choice. In addition, the FIBER FILM Contactor
is a built-in pre-wash that protects and extends the life of the carbon bed and,
in many cases, negates the need for a separate upstream pre-wash stage altogether.
Installations: MERICAT II technology was first licensed in 1986, and Merichem
has granted 43 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/mericat-ii
Contact: www.merichem.com/company/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Mericat™
and Mericat™ C
Application: Removes hydrogen sulfide (H2S) and sweetened mercaptan compounds
in gasoline/naphtha, condensate and crude oil streams.
Description: MERICAT and MERICAT C technologies employ the FIBER FILM®
Contactor as the mass-transfer device and utilize a caustic/catalyst/air mixture
as the treating reagent.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced
CAPEX and occupies less plant space, compared to most treating alternatives.
These benefits make MERICAT and MERICAT C the technologies of choice.
Installations: MERICAT technologies were first licensed in 1977, and Merichem
has granted 148 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/mericat
Contact: www.merichem.com/company/contact-us
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Mericat™ J
Application: Oxidizes heavy mercaptans in jet fuel and middle distillate streams.
Description: MERICAT J technology employs the FIBER FILM® Contactor as the
mass-transfer device, and utilizes a proprietary JeSOL™-9 solution as the treating
reagent, along with air to oxidize heavy mercaptans in jet fuel and middle distillate
streams without the need for a fixed-carbon bed.
Advantages: Since there is not a fixed-carbon bed, there is no downtime
for carbon change-out, significantly increasing the onstream factor. The use
of the non-dispersive FIBER FILM Contactor results in reduced CAPEX and less
plant space requirements compared to most treating alternatives. These benefits
make MERICAT J the technology of choice.
Licensor: Merichem
Website: www.merichem.com/jetfueltreating
Contact: www.merichem.com/company/contact-us
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Mericon™
Application: Onsite solution for the processing of spent caustics to reduce their
biological oxygen demand (BOD) and chemical oxygen demand (COD), control odor,
adjust acidity and destroy phenolics. The process is suitable in these scenarios:
• Treatment of aqueous streams containing organic material
with hazardous elements
• Substantial reduction of wastewater COD
• Wastewater streams too toxic for biological treatment
• Pre-treatment of highly contaminated wastewater to produce
a biodegradable stream
• Detoxification and/or pathogen kill of organic sludges
• Treatment of industrial liquor to economically recover metals.
Description: Wet air oxidation pre-treatment at elevated pressures and
temperatures. A totally enclosed design prevents the release of odors
from acid gases during the neutralization process.
Advantages: In cases where used caustics cannot be reclaimed, MERICON provides
a non-energy intensive and straightforward option to pre-treat the caustic before
handling in the wastewater biological treatment units. The Merichem process utilizes
solution mixing to enhance oxygen solubility—mixing within the reactor system
generates superior oxidation performance at less-severe operating conditions. As a
result, capital, operation and maintenance costs savings can be realized. Merichem
company’s patented technology produces a neutral brine effluent stream that can be
routed to wastewater treating facilities, evaporation ponds or waterways.
Operating Conditions: The primary design variables that affect oxidation
performance are reactor temperature, reactor pressure (a function of temperature),
hydraulic retention and oxygen partial pressure. Oxidation performance is most
sensitive to process temperature: with an increase in process temperature, oxygen
solubility increases and oxidation performance improves. Typically, Merichem
operating conditions range between 200°C–260°C and 35 kg/cm2–75 kg/cm2.
Economics: Minimal CAPEX is needed to meet required BOD and COD levels
and produce a non-odorous brine effluent. The process has the ability to maintain
a 100% onstream service factor between maintenance turnarounds. Specifications
for materials of construction and pH control are based on long useful life and minimal
maintenance requirements. The system design is based on minimal requirements
for operator attention.
Installations: MERICON technology was first licensed in 1988. To date, Merichem
has granted 30 operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/mericon-spent-caustic-processing
Contact: www.merichem.com/company/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Mericon™ II
Application: The MERICON family of technologies processes spent caustics to control
odor, reduce biological oxygen demand (BOD) and chemical oxygen demand (COD),
adjust pH and destroy phenolics and other hydrocarbons with an onsite solution.
This technology is used with these feedstocks:
• Spent sulfidic, phenolic, naphthenic and ethylene caustics
• Aqueous streams containing hazardous organic material
• High-COD wastewater
• Organic sludges requiring detoxification and/or pathogen kill
• Industrial liquor to economically recover metals.
Description: MERICON II produces a neutral brine effluent stream for routing
to wastewater treating facilities, evaporation ponds or waterways. It uses wet air
oxidation pre-treatment at elevated pressures and temperatures, and offers
deep neutralization options.
Advantages: In cases where used caustics cannot be reclaimed, MERICON provides
a non-energy intensive and straightforward option to pre-treat the caustic before
handling in the wastewater biological treatment units. The Merichem process utilizes
solution mixing to enhance oxygen solubility—mixing within the reactor system
generates superior oxidation performance at less-severe operating conditions.
As a result, capital, operation and maintenance costs savings can be realized.
Merichem Co.’s patented technology produces a neutral brine effluent stream
that can be routed to wastewater treating facilities, evaporation ponds or waterways.
Additional advantages include:
• Minimal capital investment
• Lower operating and maintenance costs
• Final effluent quality process guarantees
• Minimal contaminants in the final effluent
• Minimal operator attention.
Installations: MERICON technology was first licensed in 1988. To date, Merichem
has granted 30 operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/MERICON-II
Contact: www.merichem.com/company/contact-us
Operating Conditions: Merichem’s MERICON II process enhances oxygen
availability and performance at lower operating temperatures and pressures.
This process reduces CAPEX and OPEX significantly compared to other systems.
While the MERICON II typical operating conditions range between 200°C–260°C
and 35 kg/cm2–75kg/cm2 (low-medium severity), its performance can match that
of units running at higher severity.
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—NAPFINING™
and NAPFINING™ HiTAN
Application: Removes naphthenic acid compounds mainly from jet fuel, kerosine,
diesel, condensate and crude oil streams.
Description: NAPFINING and NAPFINING HiTAN technologies employ the FIBER
FILM® Contactor as the mass-transfer device and utilize caustic as the treating reagent.
Advantages: In addition, the onstream factor between routine turnarounds is 100%;
whereas, electrostatic precipitators (ESPs) are much less reliable and incapable
of processing feeds with a total acid number (TAN) higher than 0.1 mg KOH/g.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced CAPEX
and requires less plant space compared to most treating alternatives. These benefits
make NAPFINING and NAPFINING HiTAN the technologies-of-choice.
Installations: NAPFINING technologies were first licensed in 1977.
To date, Merichem has granted 75 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/napfining
Contact: www.merichem.com/company/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—OASE® yellow
Application: Under the OASE yellow brand, BASF provides customized solutions
for selective removal of sulfur components from natural gas, refinery off-gas,
Claus tail gas and acid gas enrichment units. The technology is suitable for highand low-pressure applications, such as natural gas or tail gas treatments. It comprises
different base amines in combination with promoter systems, which enable a wide
application range (e.g., CO2 can be either slipped to a maximum, or CO2 removal
can be controlled to achieve a dedicated CO2 specification in the treated gas).
Further, the removal of organic sulfur compounds such as mercaptans is possible.
Top
Formulated
MDEA MDEA
7
6
Absorber height, m
5
~12
v-ppm
~63
v-ppm
~261
v-ppm
4
3
2
Advantages: The sophisticated modelling capabilities with the new OASE® Connect
software allow flexible designs for seasonal scenarios (summer/winter operations),
plant turndown scenarios or even long-term feed gas specification changes.
Development/Delivery: Production and storage facilities in America, Europe and
Asia ensure high reliability of delivery and supply of quality solvents worldwide.
Furthermore, our regional and local presence provides for an extensive technical,
analytical and service structure that includes onsite training of customer personnel,
process optimization and turnaround assistance.
8
OASE
yellow
Description: The acid gas containing feed gas is selectively treated in an absorber
to fully or partially remove the CO2. This kind of H2S selectivity is obtained
by various measures:
• For grass root plants, the OASE yellow technology combines advanced
plant design and solvent selection to meet CAPEX and OPEX requirements.
• For existing plants, the OASE technology provides an interesting and
cost-effective alternative to meet either new regulations, specifications,
or for debottlenecking or optimization measures. To avoid any operational
interruption, solvent top up or swaps “on the fly” are possible, and can be
simulated and transferred into operation guidelines.
Economics: Due to the increased acid gas capacity and the boost in regeneration
efficiency, a reduction in equipment sizing (pumps, heat exchangers) and energy
savings of up to 35% are possible (compared with formulated MDEA). In particular,
existing low-pressure applications such as tail gas treatment experience a reduction
in circulation rate by 40%, combined with substantial reduction in H2S specification,
up to < 1 ppm in sales gas application, and < 10 ppm in tail gas treating applications.
The new solvent technology allows the combination/cascading of high- and
low-pressure absorbers.
Tail gas treatment unit, example
Corresponding absorber profiles
1
Bottom
0
0.000
0.100
0.001
H2S concentration, mol%
10.000
Installations: With more than 400 reference plants, BASF is one of the world leaders
in the gas treatment industry today.
Licensor: BASF SE
Website: energy-resources.basf.com/en/Gas-Treatment.html
Contact: energy-resources.basf.com/en/Gas-Treatment/Formulation-and-Solvents.
contact.html
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2017 REFINING PROCESSES HANDBOOK
COMPANY INDEX
Treating, Gas/Liquid—Rectisol®
Advantages: The main advantages of the process are the low utility consumption
figures, the use of an inexpensive and easily available solvent, and flexibility in
process configuration.
4
2
MeOH
injection
5
6
1
Steam
Steam
Description: The Rectisol process uses methanol (CH3OH) as a wash solvent. CH3OH
has many benefits, is globally available and is a low-cost washing agent. Furthermore,
CH3OH is chemically and thermally stable and will not change its behavior and structure
over a long service life.
The Rectisol wash unit (RWU) operates under favorable conditions at temperatures
below 0°C. To lower feed gas temperatures, it is cooled against cold product streams
before entering the absorber tower. At the absorber tower, CO2 and H2S/COS are
removed. The CO2 content in the purified gas is adjusted to a specific requirement,
which can range from 5 vppm to 5 mole%. Sulfur components, including H2S and COS,
can be removed below 0.1 vppm. The Rectisol process does not cause hydrolysis for
total COS removal.
By an intermediate flash, co-absorbed products such as hydrogen (H2) and carbon
monoxide (CO) are recovered, thus increasing the product recovery rate.
To reduce the required energy demand for the CO2 compressor, the CO2 product is
recovered in two different pressure steps (medium-pressure and lower-pressure). The CO2
product is essentially sulfur- (H2S and COS) and water-free. The CO2 products can be used
for enhanced oil recovery (EOR) and/or sequestration, or as pure CO2 for other processes.
The benefits of the RWU are that no additional downstream COS hydrolysis and/
or sulfur treatment are required. Since the CO2 product is water-free, the compressor
material can be designed from carbon steel rather than stainless material. Depending on
the allowable CO2 level in the treated gas, nearly 99% of the CO2 from the feed gas can
be concentrated in the two CO2 product streams.
In the regeneration column, loaded methanol is fully regenerated. In the H2S
fraction, sulfur components are concentrated in a sulfur-enriched stream suitable for
downstream sulfur recovery units. For low-sulfur containing feed gas streams, the
Rectisol wash can economically produce a high-sulfur enriched H2S fraction. After
cooling, the CH3OH is used in the absorber tower to wash out CO2 and H2S/COS.
The water contained in the feed gas is withdrawn from the process in CH3OH/
water separation. The amount of water purged from the process is driven by water
concentration in the feed gas (water saturation at battery limit).
H2S fraction
Feed gas
Refr.
Application: Rectisol is a gas purification process for removal of carbon dioxide (CO2 )
down to mol% and/or vppm levels, and hydrogen sulfide (H2S)/carbonyl sulfide (COS)
down to 0.1 vppm from a feed gas downstream of a gasifier—e.g., GE-Energy, Shell,
ConocoPhillips, ECUST and others.
Cooling
PROCESS CATEGORIES
3
CO2
product
CO2
product
Treated gas
Performance:
Feed gas
1 Feedgas cooling
2 Absorber column
3 Intermediate flash
4 CO2 product
5 Regeneration column
6 Methanol/water separation
Waste
water
From different gasification types (GE Energy, Shell,
ConocoPhillips, ECUST, etc.)
Treated gas
Adjusted in CO2 content (5 vppm to 5 mol%), H2S + COS <
0.1 vppm (without additional downstream treatment)
CO2 capture
Up to 99%
CO2 product
For EOR and/or sequestration, substantially free of H2S and
COS without COS hydrolysis, water-free without additional drying
H2S fraction
Suitable for downstream sulfur recovery unit,
and for low-sulfur containing feed gases.
Installations: More than 75 Rectisol wash units have been engineered and supplied
by Linde worldwide, primarily in China, the US, Africa and Europe.
Licensor: Linde AG
Website: www.leamericas.com/rectisol
Contact: www.leamericas.com/en/contact
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—
Refinery Fuel Additives
Application: Increasing worldwide demand for diesel, more stringent environmental
legislation for transportation fuels and changing fossil energy resources. Refiners are
facing a lot of challenges: BASF’s Refinery Additives offer a wide range of solutions.
Description: From cold-flow improvers that ensure the operability of diesel fuels even
at cold temperatures, and lubricity additives that prevent wear in diesel distribution
pumps, to anti-statics that provide a minimum conductivity in low-sulfur fuels, BASF’s
Refinery Additives are an answer to many problems of modern fuel production.
• Keroflux®
• Kerostat®
• Kerobit®
• Keropon®
• Kerofine®
• Kerobrisol®
• Kerofluid®
• Keromet®
Development/Delivery: With a worldwide distribution network and backwardintegration into key raw material, BASF’s Refinery Additives offer maximum supply
chain reliability. A global network of technical service centers provides optimal support
by a committed team helping our customers to be more successful. Steady product
improvement ensures the best product performance in a fast-changing environment.
Installations: With more than 400 reference plants, BASF is one of the world leaders
in the gas treatment industry today.
Licensor: BASF
Website: energy-resources.basf.com/en/Gas-Treatment.html
Contact: energy-resources.basf.com/en/Gas-Treatment/Formulation-and-Solvents.
contact.html
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—REGEN®
Application: Processes regenerable rich-caustic streams produced in the refinery,
which allows it to be recycled, significantly improving caustic utilization.
Description: Typically, REGEN is coupled with extractive THIOLEX™ to regenerate
the mercaptide-rich caustic purged from the THIOLEX system, and then returning
a lean-caustic stream for additional mercaptan removal. Depending on the
stringency of the treated product specifications, the REGEN design will employ
disulfide oil (DSO) gravity separation and/or solvent washing step(s) to minimize
the impact of DSO back-extraction.
Advantages: REGEN technology is equally effective at reviving rich/spent caustic
streams emanating from conventional refinery treating units. Moderate levels
of sodium sulfide [salt of hydrogen sulfide (H2S)] can be accommodated in the
rich caustic, and many times negates the need for a H2S pre-wash stage in the
hydrocarbon extraction section of the treating unit, resulting in lower CAPEX.
The design of the system is based on more than 75 yr of first-hand operating
knowledge gained from Merichem-owned plants. These benefits, coupled with
Merichem’s extensive licensing experience, make REGEN the technology-of-choice.
Installations: REGEN technology was first licensed in 1980. To date, Merichem
has granted 151 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/regen
Contact: www.merichem.com/company/contact-us
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Shell CANSOLV®
SO2 Scrubbing System
Application: The Shell CANSOLV SO2 Scrubbing System is suited to remove sulfur
dioxide (SO2 ) selectively from a wide range of applications to produce a concentrated
SO2 stream. The system has been applied on Claus plant tail gas (Cansolv TGT+
Process), fluid catalytic cracker (FCC) regenerator off-gas, coker off-gas, spent acid
plant tail gas, utility boiler flue gas and a wide range of metallurgical and power
applications.
The process can also be used for carbon dioxide (CO2 ) removal in similar conditions.
Description: Shell CANSOLV process is a regenerable flue gas treating solution in
which a solvent selectively removes SO2 from flue gases. The flue gas is typically
cleaned of impurities in an water scrubbing system before contacting the solvent in
an absorption tower. The flue gas leaves the absorption tower with low residual levels
of SO2 . The SO2 -rich solvent is then regenerated in a dedicated stripping tower using
low-pressure steam: the concentrated SO2 product leaves the top of the tower and
the regenerated solvent is returned to the absorption tower. The concentrated SO2
stream can then be used as partial feedstock for a sulfur recovery unit (modified Claus
process) or as a direct feedstock for a sulfuric acid (H2SO4) plant.
In the case of CO2 capture, the process operates on similar principles, with the
main differences being the solvent used in the system and the final destination of the
concentrated CO2 product. Concentrated CO2 can be used for enhanced oil recovery, for
CO2 sequestration in depleted fields or even as feedstock for various chemical processes.
Operating conditions: As with most amine-based gas treating systems, Shell
CANSOLV can be adapted to treat flue gases with varying levels of SO2 contamination
by changing the solvent circulation and throttling environmental performance by
varying regeneration medium input (LP steam, thermal fluid).
Temperature, °C
Pressure, bar
Yields:
Flue gas
SO2
CO2
Concentrated product
SO2
CO2
Absorption
20–70
~0
Regeneration
100–130
~0.5–1.0
Units
ppmv
% removal
< 10 to < 200
> 90%
vol% dry
vol% dry
99.9
99.9
Treated gas
Absorbent
purification
unit
Pretreatment
Effluent
Condenser
Regeneration
column
Absorption
column
Feed gas
SO2 product
Filteration
system
Lean
absorbent
tank
Lean
absorbent
cooler
Rich absorbent
Reboiler
Lean absorbent
Advantages: Compared with traditional non-regenerable flue gas desulfurization
systems, Shell CANSOLV requires low chemical consumption and produces
low quantities of liquid/solid waste. In addition, the concentrated SO2 product
can be monetized in the form of solid sulfur or H2SO4.
Development/Delivery: Shell CANSOLV was developed in the mid-1990s, primarily
aimed at treating SO2 from coal-fired power plants and any other SO2 -bearing flue
gas. The first applications started in 2002 on the Claus process and acid plant tail gas.
Installations: Over the past 15 years, more than 25 Shell CANSOLV units have been
licensed, with six now in the design/construction/commissioning phase. The process
has been applied in refineries, gas plants, metallurgical plants, fertilizer plants and
power stations, and has been treating flue gases from 4 MNm3/h–5.2 MMNm3/h.
It has been used across the world to produce H2SO4 or to increase sulfur plant
processing capacity, while ensuring environmental compliance.
Continued 
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—Shell CANSOLV® SO2 Scrubbing System (cont.)
The SaskPower Boundary Dam 3 system includes both SO2 and CO2 capture,
and is the first full-scale, post-combustion carbon capture system in the world. It
has been in operation since 2013, delivering CO2 for enhanced oil recovery at a rate
approaching 1 MMtpy.
References:
1. Lebel, M. and M. Jacques, “Regenerable tail gas treatment,” PTQ, 4Q 2016, and
SOGAT 2016, Abu Dhabi, UAE, 2016.
2. Wang, L. F. and M. Lebel, “SO2 emissions control in China,” Sulphur Magazine,
September 2016.
3. Kohlbrugge, A., “Controlling emissions during SRU start-ups,” Sulphur Magazine,
July 2013.
4. Gelder, J., “Cleaning up high-sulphur residue: Technology for helping refiners to
minimize SO2 emissions,” Impact, Iss. 2, 2013.
5. Lebel, M., J. Gelder, N. Moreton, A. Slavens, B. DeWeed, B. Murphy, R. So and
S. Pollitt, “Something for nothing: How Middle Eastern SRUs can benefit from
increasing SOx emissions stringency,” SOGAT 2013, Abu Dhabi, UAE, 2013.
6. Anghel, A., “Setting new standards: How PDO achieved ultra-deep sulfur recovery
on its highly sour oil and gas development mega-project,” Impact, Iss. 3, 2012.
7. Charest, S., “Controlling sulphur in China’s power sector: Major coal-fired power
plant adapts Cansolv’s technology to control SO2 emissions and minimize landfill
requirements,” Impact, Iss. 2, 2012.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/gasprocessing
Contact: gasprocessing@shell.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—
Sour Gas Treatment
Application: The Wet gas Sulfuric Acid (WSA process) treats all types of sulfurcontaining gases such as amine and Rectisol regenerator offgas, SWS gas and
Claus plant tail gas in refineries, gas treatment plants, petrochemicals and coke
chemicals plants. The WSA process can also be applied for sulfur oxide (SOx )
removal and regeneration of spent sulfuric acid. Sulfur, in any form, is efficiently
recovered as concentrated commercial-quality sulfuric acid.
Description: Feed gas is combusted and cooled to approximately 400°C in a waste
heat boiler. The gas then enters the SO2 converter containing one or several beds
of SO2 oxidation catalyst to convert SO2 to SO3. The gas is cooled in a gas cooler
whereby SO3 hydrates to H2SO4 (gas), which is finally condensed as concentrated
sulfuric acid (typically 98% w/w). The WSA condenser is cooled by ambient air,
and heated air may be used as combustion air for increased thermal efficiency.
The heat released by combustion and SO2 oxidation is recovered as steam.
The process operates without removing water from the gas. Therefore, the number
of equipment items is minimized, and no liquid waste is formed. Cleaned process
gas leaving the WSA condenser is sent to stack without further treatment.
The WSA process is characterized by:
• Very high recovery of sulfur as commercial-grade sulfuric acid
• No generation of waste solids or wastewater
• No consumption of absorbents or auxiliary chemicals
• Efficient heat recovery ensuring economical operation
• Simple and fully automated operation adapting to variations
in feed gas flow and composition.
Superheated steam
Blower
Combustion air
Stack gas
SO2
converter
BFW
Steam
drum
Blower
Interbed
cooler
Interbed
cooler
H2S gas
Combustor
WHB
Gas
cooler
Air
WSA
condenser
Acid cooler
Product acid
Installations: More than 150 units worldwide.
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/processes/sulfur-removal
Contact: fej@topsoe.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—
Spent acid regeneration
Application: The Wet gas Sulfuric Acid (WSA) process treats spent sulfuric acid
from alkylation, as well as other types of waste sulfuric acid in the petrochemical
and chemicals industry. Amine regenerator offgas and/or refinery gas may be used
as auxiliary fuel. The regenerated acid will contain a minimum of 98% H2SO4 and
can be recycled directly to the alkylation process. The WSA process is also applied
for conversion of hydrogen sulfide H2S and removal of SOx.
Description: Spent acid is decomposed to SO2 and water vapor in a combustor
using amine regenerator offgas or refinery gas as fuel. The SO2 containing flue gas
is cooled in a waste-heat boiler and solid matter originating from the acid feed is
separated in an electrostatic precipitator. By adding preheated air, the process gas
temperature and oxygen content are adjusted before the catalytic converter converts
SO2 to SO3. The gas is cooled in the gas cooler, whereby SO3 is hydrated to H2SO4
(gas), which is finally condensed as 98% sulfuric acid. The WSA condenser is cooled
by ambient air. The heated air may be used as combustion air for increased thermal
efficiency. The heat released by combustion and SO2 oxidation is recovered as steam.
The process operates without removing water from the gas. Therefore,
the number of equipment items is minimized and no liquid waste is formed.
This is especially important in spent acid regeneration where SO3 formed by
the acid decomposition will otherwise be lost with the wastewater.
The WSA process is characterized by:
• No generation of wastewater
• No consumption of absorbents or auxiliary chemicals
• Efficient heat recovery ensuring economical operation
• Simple and fully automated operation adapting to variations in feed flow
and composition.
Superheated steam
Blower
Combustion air
ESP
BFW
Steam
drum
Spent
acid
H2S gas/
fuel gas
Combustor
WHB
Stack gas
SO2
converter
Blower
Interbed
cooler
Interbed
cooler
Gas
cooler
Air
WSA
condenser
Acid cooler
Product acid
Installations: More than 150 units worldwide, including 20 for spent acid regeneration
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: www.topsoe.com/processes/sulfur-removal
Contact: fej@topsoe.com
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—THIOLEX™
Application: Removes acid gas and mercaptan compounds from liquid and gas
hydrocarbon streams.
Description: THIOLEX technology employs the FIBER FILM® Contactor
as the mass-transfer device, and utilizes caustic as the treating reagent.
Advantages: The non-dispersive FIBER FILM Contactor achieves reduced
CAPEX and requires less plant space compared to most treating alternatives.
These benefits make THIOLEX the technology-of-choice.
Installations: THIOLEX technology was first licensed in 1980. To date, Merichem
has granted 220 unit operating licenses worldwide.
Licensor: Merichem
Website: www.merichem.com/company/technologies/thiolex
Contact: www.merichem.com/company/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Treating, Gas/Liquid—
Ultra-low-sulfur diesel (ULSD)
Makeup hydrogen
Application: Haldoer Topsoe’s ultra-low-sulfur diesel (ULSD) process is designed
to produce ULSD (less than 10 wppm of sulfur) from cracked and straight-run
distillates, as well as renewable feeds by co-processing or stand-alone unit.
By selecting the proper catalyst and operating conditions, the process can be
designed to produce 5 wppm sulfur diesel at low reactor pressures (<500 psig),
or at higher reactor pressure when products with improved density, cetane
and polyaromatics are required.
Description: Topsoe ULSD process is a hydrotreating process that combines
Topsoe’s understanding of deep-desulfurization kinetics, high-activity catalyst,
state-of-the-art reactor internal and engineering expertise in the design of new
and revamped ULSD units. The ULSD process can be applied over a very wide range
of reactor pressures. Our highest activity BRIM® catalysts are specifically formulated
with high-desulfurization activity and stability at low reactor pressure (about
500 psig) to produce 5 wppm diesel. This catalyst is suitable for revamping existing
low-pressure hydrotreaters or in new units when minimizing hydrogen consumption.
The highest activity HyBRIM™ catalyst is suitable at higher pressure when secondary
objectives such as cetane improvement and density reduction are required.
Topsoe offers a wide range of engineering deliverables to meet the needs of
the refiners. Our offerings include process scoping study, reactor design package,
process design package or engineering design package.
Installations: Topsoe has licensed more than 100 ULSD hydrotreaters designed
for less than 10 wppm sulfur in the diesel. Our reactor internals are installed
in more than 100 ULSD units.
Recycle gas
compressor
Furnace
Absorber
Lean amine
Reactor
Rich amine
H2 rich gas
Fresh feed
Product to
fractionation
High-pressure
separator
Low-pressure separator
Licensor: Haldor Topsoe A/S, Refinery Business Unit
Website: Topsoe.com
Contact: mkj@topsoe.com
References:
1. Sarup, B., M. Johansen, L. Skyum and B. Cooper, “ULSD Production in Practice,”
ERTC, Prague, November 2004.
2. Hoekstra, G., V. Pradhan, K. Knudsen, P. Christensen, I. Vasalos and S. Vousvoukis,
“ULSD: Ensuring the unit makes on-spec. product,” NPRA Annual Meeting,
Salt Lake City, March 2006.
3. Egebjerg, R., K. Knudsen and E. Grennfelt, “Bigger is better: Industrial-scale
production of renewable diesel,”NPRA Annual Meeting, San Antonio, Texas,
March 2011.
4. Hanson, T., “Hydrotreater revamp case story: Making the most of what you have,”
ERTC, Istanbul, November 2010.
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Upgrading, Heavy Oil—
Eni Slurry Technology (EST)
Application: Eni Slurry Technology (EST) represents a significant technological
innovation in residue conversion and unconventional oil upgrading, and marks a step
change in the treatment of the heavy end of the barrel. EST can be classified as a
hydrocracking process, while the peculiar characteristics concern: the use of dispersed
catalysts, and an original process scheme for catalyst handling that allow almost total
feedstock conversion as well as high upgrading performance. Typical feeds include
atmospheric and vacuum residues, heavy and extra-heavy oils, bitumen from oil sands,
deasphalter bottoms, visbroken tars and other high-boiling point feedstocks.
Description:
A plant based on EST consists of the following sections:
• Slurry reactors are the core of EST technology. Vacuum residue (VR), or a
heavy residue, is preheated and mixed with catalyst precursor and vacuum
recycle, and fed to the slurry bubble-column reactors, together with hydrogen
(H2 )-rich recycle gas. The reactors partially convert the VR to light gases,
naphtha, middle distillates and vacuum gasoil. The effluent from each slurry
reactor is sent to the corresponding hot high-pressure separator (HHPS).
• Recycle gas loop. The vapor phase from the HHPSs is cooled and sent to the
wash oil column to eliminate the heavy hydrocarbon entrainment. The wash
oil column overhead is cooled, condensed and sent to the cold high-pressure
separator (CHPS). The light hydrocarbon phase from the CHPS is sent to the
light products fractionation section.
• Slurry fractionation. Liquids from the HHPSs are sent to the hot low-pressure
separator (HLPS). The liquid is fed to a slurry stripper to separate the lighter
hydrocarbons. The stripper overhead is washed with vacuum gasoil (VGO)
from the vacuum column and sent to the preflash column, together with
the vapors coming from the HLPS. From the top of preflash column, the
condensed vapors are partially used as column reflux, and the remainder is
sent to battery limits (or upgrading section). The bottom of the preflash is sent
to the vacuum column. From here, a “light VGO” cut is sent to the wash oil
column, products (LVGO and VGO) are sent to battery limits (or upgrading),
and the bottom stream, rich in asphaltenes and catalyst, is recycled to the
slurry reaction section, while a minimum purge is delivered to the battery limits
to maintain the correct level of metals. The purge can be treated in different
ways, such as metal recovery, gasification and as feedstock for a steel factory.
Operating conditions: The slurry reactors are almost isothermal axially and radially,
and operate between 425°C–435°C (depending on the feedstock) and at a pressure
of 160 bara.
Yields: For a typical vacuum residue, the yields of the slurry section are:
Products
Product yields, wt%
Gas/LPG
6–12
Naphtha < 450 ppm S
10–20
Kero cut + diesel
35–45
VGO
25–35
Purge *
5–7
*The yield of purge can be further reduced by 1%–2% with static decanter treatment.
Upgraded product qualities:
Product qualities
Naphtha
Diesel, Euro 5
Sulphur, wt ppm
<1
<5
Nitrogen, wt ppm
<1
<5
Cetane index
51, min.
Polyaromatics, wt%
<8
Metals, wt ppm
VGO
< 500
< 500
<1
Continued 
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2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Upgrading, Heavy Oil—Eni Slurry Technology (EST) (cont.)
Advantages: The process allows almost full conversion of the residue to valuable
distillates, avoiding the production of residual byproducts, such as pet coke or
heavy fuel oil.
Economics:
Investment: Compared to other conversion technologies, the introduction of
an EST plant in a refinery greatly enhances economics. The absence of fuel oil and pet
coke in the product slate makes the contribution margin of an EST plant 30% higher
compared to an ebullated bed, and 40% higher comparted to delayed coking. Looking
beyond 2020, the relative contribution margin will widen in favor of EST technology.
Utilities: Specific consumption per ton of fresh feed:
EST plant
Specific consumption
Slurry section
(slurry and upgrader section)
Fuel gas, tons
0.015
0.0266
LP steam, tons
-0.1
0
MP steam, tons
0.21
0.21
HP steam, tons
0.17
0.17
CW, m3
9.5
9.5
Electricity, MWh
0.13
0.13
Development/Delivery: The first 0.5-bpd pilot plant was built at Eni laboratories in
Milan in the early 1990s. Prior to the construction of an industrial plant, a 1,200-bpd
commercial demonstration plant (CDP) that was operational from 2005 was built at
the Taranto refinery.
The technology was tested with a wide range of heavy residues, such as VR from
Ural crude, Athabasca bitumen and a Middle East heavy crude oil, as well as visbroken
tar. The Taranto CDP processed more than 160,000 bbl of black feed with excellent
results, with purge at a steady-state condition of 2 wt%.
The first full-scale industrial plant in operation based on a slurry hydrocracking
process was built at Eni’s Sannazzaro refinery. The EST project began in January 2009
with the front-end engineering. The first oil in was in October 14th, 2013.
Eni, with the support of Saipem, directly managed the entire construction project
of the EST complex without an EPC main contractor. The upgrading section of the
complex was designed by Topsoe and uses a proprietary catalyst.
Installations: The only industrial application of EST is at Eni’s Sannazzaro de’
Burgondi refinery. The EST unit has a design capacity of 23,000 bpd and allows the
Sannazzaro refinery to convert the bottom-of-the-barrel into diesel and other valuable
refinery streams (LPG, naphtha, jet fuel, etc.).
Eni began licensing the EST technology in 2016 and has awarded two licenses to
major refiners. An EST plant is now under design.
References:
1. Bellussi, G., G. Rispoli, D. Molinari, A. Landoni, P. Pollesel, N. Panariti, R. Millini and
E. Montanari, “The role of MoS2 nano-slabs in the protection of solid cracking
catalysts for the total conversion of heavy oils to good-quality distillates,”
Catalysis Science & Technology, Iss. 1, 2013.
2. Delbianco, A., S. Meli, L. Tagliabue and N. Panariti, “Eni Slurry Technology:
A new process for heavy oil upgrading,” 19th World Petroleum Congress,
Spain, 2008.
Licensor: Eni S.p.A. Refining & Marketing
Website: www.eni.com/docs/en_IT/enicom/publications-archive/company/
operations-strategies/refining-marketing/eni_EST_esecutivo.pdf
Contact: giacomo.rispoli@eni.com
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Upgrading, Heavy Oil—
FLEXICOKING™ technology
Application: ExxonMobil’s commercially proven process for flexible resid upgrading.
Description: FLEXICOKING™ technology converts low-cost feeds—deep-cut vacuum
resid, atmospheric resid, oil sands bitumen, heavy-whole crudes and deasphalting
unit, fluid catalytic cracking (FCC) and ebullated-bed bottoms—into high-value
products. The technology is beneficial when coking for complete resid conversion
with low or no fuel oil production is preferred, when outlets for fuel coke are limited
or uneconomical, and particularly when low-cost fuel gas is needed or where natural
gas cost is high.
Advantages: Technological advantages include:
• Cost-effective investment
° Simple, integrated steam/air gasification and carbon steel construction
° Reduced plot space requirement
• Environmental benefits
° Continuous, non-batch operation and closed-coke handling system,
resulting in low particulate and fugitive hydrocarbon emissions
° Converts coke to clean, economical FLEXIGAS, which lowers sulfur
oxides (SOx ) and nitrogen oxides NOx ) emissions
• Flexible and multipurpose (i.e., handles a wide-variety of feeds)
• Reliable
° Commercially proven for more than 40 yr in ExxonMobil and
in licensed third-party units
° Reliable operations with service factors that routinely exceed 92%.
References:
1. SFA Pacific Inc., “Upgrading heavy oils and residues to transportation fuels,”
October 2009.
2. Kamienski, P. W., G. Phillips and M. de Wit, Hydrocarbon Engineering,
March 2008.
Installations: FLEXICOKING services typically include consultation from design
through the startup phases of project implementation and beyond.
Licensor: ExxonMobil Catalysts & Licensing LLC.
Website: www.catalysts-licensing.com
Contact: www.exxonmobilchemical.com/en/resources/contact-us
Copyright © 2017 Gulf Publishing Company. All rights reserved.
2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Upgrading, Heavy Oil—Gasification
Application: The Shell Gasification Process (SGP) converts heavy refinery residual
liquid hydrocarbon streams with high sulfur and metals content into clean synthesis
gas [syngas, a mixture of hydrogen (H2 ) and carbon monoxide (CO)] and marketable
metal oxides. Sulfur is removed using standard gas treating processes and sold as
elemental sulfur. The process converts residual streams, with virtually zero value
as fuel-blending components, into marketable, clean syngas and byproducts. This
syngas can be used to make H2 by applying a CO-shift and pressure swing adsorption
technologies to produce chemicals such as oxo-alcohols, ammonia and methanol, or
to generate power in gas turbines. It is one of the few environmentally acceptable
solutions for residual hydrocarbon streams.
Description: The liquid hydrocarbon feedstock—from light (such as vacuum residue),
to very heavy ( such as cracked residues or asphalt)—is fed into a reactor and gasified
with pure oxygen and steam. The net reaction is exothermic and produces a gas
containing primarily CO and H2 .
The SGP uses refractory-lined reactors fitted with a gasification burner and a
syngas effluent cooler, designed to produce high-pressure steam up to 120 bara. Gases
leaving the steam generator are cooled further in an economizer.
Soot (unconverted carbon) and ash are removed from the raw syngas by a twostage water wash. After the final scrubbing, the gas is virtually particulate-free and
is then routed to an acid gas removal system. Net water from the scrubber section is
routed to the soot ash removal unit (SARU) to filter out soot and ash before returning
it to the scrubber. By controlled oxidation of the filter cake, ash components are
recovered as marketable metal oxides, nickel (Ni) and vanadium (V).
Operating conditions: Operating pressures range from 25 bara–65 bara,
depending on the final syngas application. The operating temperature ranges
from 1,300°C–1350°C.
Yields: The typical yield is greater than 2.6 Nm3/kg syngas. Steam production
is approximately 2.2 t/t feed.
Advantages: Oxygen consumption is less than 1 kg/kg feed; long burner life;
high availability; no waste; can process a wide-variety of feedstocks;
highly-automated and safeguarded system
Process
steam
Syngas
Oil
Steam
Oxygen
Scrubber
Boiler
Reactor
Effluent
boiler
Soot quench
Economics:
Utilities:
99.5 vol% oxygen
Superheated steam
Electricity
Bleed to SWS
BFW
Filtercake
work up
Ni/V ash
Filtration
<1 kg/kg feed
0.5 kg/kg feed
~1 MW
Installations: Over the past 60 years, more than 170 SGP units that convert residue
feedstock into syngas have been installed for various applications. The Shell Pernis
refinery in the Netherlands uses the SGP process in a close refinery integration.
This highly complex refinery depends on the SGP process for its H2 supply, and
is now revamping it to enable full disposal of a new asphalt stream. Eni’s refinery
in Italy uses syngas for its H2 supply and power production. Similar projects have
started up in Canada and China. In Saudi Arabia, the Jazan integrated gasification
combined-cycle plant that is under construction will be the largest residue gasification
plant in the world.
Continued 
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Upgrading, Heavy Oil—Gasification (cont.)
References:
1. “Shell Gasification Process,” Defining the Future Conference, Bahrain,
June 1–2, 2004.
2. “Shell Gasification Process for upgrading Gdansk refinery,” 6th European
Gasification Conference IChemE, Brighton, UK, May 10–12, 2004.
3. “Overview of Shell Global Solutions worldwide gasification developments,”
2003 Gasification Technologies Conference, San Francisco, California,
October 12–15, 2003.
4. “Shell Gasification Technology—Optimal disposal solution for refineries
heavy ends,” ERTC Gasification Conference, Paris, France, 2007.
5. “Shell Gasification Technology: Generating profit from the bottom of the barrel,”
NPRA, Annual Meeting, San Diego, California, March 9–11, 2008.
6. “Shell Gasification Technology—Part of refinery upgrading strategies,”
ERTC Gasification Conference, Rome, Italy, April 21–23, 2008.
7. “Interview service manager liquid and gas gasification Shell Global Solutions Int.,”
Petroleum and Chemical Construction, China, February 2011.
8. “Residue gasification—An attractive bottom of the barrel upgrading technology,”
12th European Gasification Conference IChemE, Rotterdam, the Netherlands,
March 2014.
9. “Solvent deasphalting (SDA)—Residue gasification,” Hydrocarbon Processing
Supplement, 2016.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
2017 REFINING PROCESSES HANDBOOK
PROCESS CATEGORIES
COMPANY INDEX
Upgrading, Heavy Oil—LC-SLURRY
Makeup H2
Application: High-conversion hydrocracking, desulfurization, demetalization,
CCR reduction of vacuum resids, SDA pitch and FCC slurry oil using the LC-SLURRY
process. LC-SLURRY uses the LC-FINING reactor platform, where catalyst is moved
from a reactor with liquid effluent and separated in the catalyst de-oiling section.
The LC-SLURRY flow scheme is similar to the LC-FINING scheme with the exception
of CDS.
LC-slurry 1
reactor
3
6
2
Products: A full range of high-quality distillates. Residual products can be used
as coker feedstock or synthetic crude. Alternately, it can be used as a low-sulfur
fuel oil or feedstock for a resid FCCU.
Description: Fresh hydrocarbon liquid feed is mixed with hydrogen (H2), fresh active
slurry catalyst and recycle equilibrium catalyst, and then reacted within a slurry
reactor (1) maintained in turbulence by liquid upflow to achieve efficient isothermal
operation. Product quality is constantly maintained at a high level by the continuous
addition of fresh and recycle catalyst, and withdrawal through catalyst de-oiling.
Reactor products flow to a high-pressure separator (2), inline hydrotreater (3),
heavy oil stripper (4), cold high-pressure separator for recycle gas separation
and cleanup (5, 6), product fractionator (7) and catalyst de-oiling (CDS).
Process features can also include a second-stage hydrocracker and heavy oil
treater. The technology has the flexibility to produce 80 vol% diesel with about 1
vol%–6 vol% low-sulfur fuel oil, or produce about 60 vol% diesel with 25% RFCC feed.
Yields:
Feed
Gravity, °API
Sulfur, wt%
Ni/V, ppmw
Conversion, vol% (1,022 °F+)
Russian
7.35
2.98
98/344
97.1
Products vol%
C4
Naphtha
Euro 5 diesel
LSFO (680°F+)
Diesel °API/wt% sulfur
LSFO, wt% sulfur
Russian
4.21
28.33
79.88
5.8
40/0.0005
< 0.2
Vacuum resid
VR Blend
5.12
4.75
80/257
97.1
Arabian Light
4.8
4.45
27/94
97.2
Russian/Basrah Arabian Light
4.27
4.22
28.91
28.9
79.3
79.4
5.89
5.75
40/0.0005
40/0.0005
< 0.5
< 0.5
Recycle H2
Steam
5
Hydrocarbon
feed
4
Fresh
catalyst
CDS
Unconverted oil
Spent dry
catalyst
7
Treated
products
Catalyst recycle
Operating conditions:
Reactor temperature, °F
Reactor pressure, psig
H2 partial pressure, psig
LSHV
Conversion, %
Desulfurization, %
Demetalization, %
CCR reduction, %
725–840
1,400–3,500
1,000–2,700
0.1–0.4
90–99+
80–99
95–99
80–99
Economics:
Investment, estimated (US Gulf Coast, 2017)
Size, bpsd fresh feed
50,000
$/bpsd typical fresh feed
12,000
Continued 
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Upgrading, Heavy Oil—LC-SLURRY (cont.)
Utilities, per bbl fresh feed
Fuel fired, 103 Btu
Electricity, kWh
Steam (export), lb
Water, cooling, gal.
90
16
10
120
Installations: Nine LC-FINING units are in operation, and one LC-SLURRY unit
is in engineering.
Licensor: Chevron Lummus Global LLC
Website: www.chevronlummus.com
Contact: GoutamBiswas@chevron.com
2017 REFINING PROCESSES HANDBOOK
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Upgrading, Heavy Oil—MPG™
Application
Multi-product gasifier uses all kinds of liquid hydrocarbon residues from refinery
or chemical processes for the production of syngas by non-catalytic partial oxidation.
Typical feedstocks are high-viscous, low-reactivity, heavy residue from oil
refining—e.g., asphalt, bitumen, tar, visbreaker residue, hydrocracker residue,
FCC residue, vacuum residue, coal tar, oil-sands tar, etc.
Products are syngas (H2 + CO) with no coproducts.
Description
MPG can process up to 200,000 Nm3/hr dry syngas per gasifier.
The feedstock, together with O2 and steam, is fed via the proprietary MPG burner
into the refractory-lined entrained flow reactor operating at 30 barg–100 barg, where
it reacts in noncatalytic partial oxidation at typically 1,200°C–1,500°C to form syngas.
The syngas leaving the bottom of the reactor is cooled by quench or in a waste heat
boiler, depending on feedstock characteristics and downstream usage.
Advantages
The proprietary MPG burner design allows a wide variety of feedstock properties
to be handled safely and reliably, covering high viscosity and even occasional particles
up to millimeter size. The pressurized water cooling of the burner ensures safe
operation under all conditions.
The technology may also be adapted to the usage of slurries with solid content
or bio-based syncrude.
Economics
Individual costs vary significantly depending on feedstock, size, location,
integration in refinery, etc.
CAPEX: $180 MM–$400 MM
Residue
Value
Steam
Feedstock
MPG™
(quench)
Raw gas
shift
LP steam
Pure O2
High-Btu low-sulfur fuel gas
Gas
cooling
Rectisol™
Rectisol™
O2
Quench
water
ASU
Soot water
filtration
Air
Filter cake
Hydrogen
H2S + CO2
O2
Sulfur
OxyClaus™
Claus offgas
Website
www.engineering-airliquide.com/syngas
Contact
syngas@airliquide.com
Installations
Pre-1997: 26 gasification plants with 76 reactors build as an exclusive sub-licensor
for Shell Gasification Process.
1997: Acquisition of commercially proven technology from SVZ and
enhancements by Lurgi for operating pressure and lifetime of burner.
Since 2000: Three gasifers (heavy residue) with MPG technology.
Latest reference: 130,000 Nm3/hr H2 from hydrocracked residue/vacuum residue
from oil-sands upgrading in Canada; started up in 2016.
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Upgrading, Heavy Oil—
Resid to Propylene—R2P™
Application: Selective conversion of heavy feedstocks into petrochemical products
into C3–C4 olefins, in particular propylene, high-octane gasoline, aromatics.
Description: Based on the R2R™ resid fluid catalytic cracking (RFCC) process
using a riser and a double regenerator for gasoline production, this new
petrochemical version is oriented toward light olefins, particularly propylene,
and aromatics. The process is characterized by the use of two independent risers: the
main riser cracks the resid feed under conditions to optimize fuels production; and
the second PetroRiser™ riser is operated to selectively crack
specific recycle streams to maximize propylene production.
The RFCC process applies a short contact-time riser, proprietary injection
system and severe cracking conditions for bottoms conversion. The temperature
and catalyst circulation rates are higher than those used for a conventional gasoline
mode operation. The main riser temperature profile can be optimized with a mixed
temperature control (MTC) system.
Reaction products are then rapidly separated from the catalyst through
a high-efficiency riser termination device (RS2 ).
Recycle feed is re-cracked in the PetroRiser under conditions that are
substantially more severe than in the main riser. A precise selection of recycle
cuts, combined with adapted commercial FCC catalysts and additives, lead to
high propylene yields with moderate dry gas production.
The deactivated catalyst from both the main riser and PetroRiser are collected
into a single packed stripper, which enhances the steam stripping efficiency
of the catalyst.
Catalyst regeneration is carried out in two independent stages to minimize
permanent hydrothermal activity loss. The first stage is operated in a mild partialcombustion mode that removes produced moisture and limits catalyst deactivation,
while the second stage completes the combustion at higher temperatures to fully
restore catalyst activity. The R2R system is able to process residue feed containing
high metals and CCR using this regenerator configuration, and even higher contents
with the addition of a catalyst cooler.
The recycle feeds that are typically used in the PetroRiser are light and
medium FCC gasoline, as well as olefin streams coming from an oligomerization
unit. This last option is of particular interest under market conditions that favor
propylene over C4 olefins.
The reaction and regeneration sections use a cold-wall design that results
in minimum capital investment and maximum mechanical reliability and safety.
Units are tailored to fit market needs (feedstock and product slate) and can
include a wide range of turndown flexibility. Available options include power
recovery, waste heat recovery, flue gas treatment, slurry filtration and light olefins
recovery and purification.
Installations: PetroRiser technology is available for revamp of all RFCC and
FCC units. Axens and TechnipFMC, members of the FCC Alliance, have licensed
more than 60 FCCUs, and performed more than 250 revamp projects.
Continued 
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2017 REFINING PROCESSES HANDBOOK
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Upgrading, Heavy Oil—Resid to Propylene—R2P™ (cont.)
References:
1. “Resid to propylene,” ERTC Annual Meeting, 2008, Vienna.
Licensor: TechnipFMC and Axens license this technology.
Website: www.axens.net/product/technology-licensing/20043/
r2p-resid-to-propylene.html
Contact: steve.shimoda@technipfmc.com
2017 REFINING PROCESSES HANDBOOK
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Upgrading, Heavy Oil—ROSE®
plus Hydrocracker
Atmospheric distillates
HDS
Application: Process designed for upgrading vacuum residuum (VR) by the recent
success of ROSE plus hydrocracker, increasing middle distillates and reducing residue.
Description: This configuration has a higher rate of return on investment (ROI)
when compared with traditional deep-conversion and higher-complexity upgrading
technologies and methods.
VR is upgraded through the ROSE unit to provide higher-quality deasphalted oil
(DAO), which makes up part of the feed to the mild-hydrocracker (MHC) to improve
run length and increase conversion to produce higher-quality products. The ROSE
unit was implemented in 2011, when contaminants most detrimental to hydrocrackers
showed the sharpest partitioning in ROSE. This allowed for the good-quality DAO
to make up about half the feed to the hydrocracker. Additionally, this configuration
allowed the hydrocracker to achieve almost 90% conversion.
There is a long catalyst run (more than 3 years) between change-outs or
regeneration/skimming, since DAO is low in metals, sulfur and carbon compared
with resid. Almost complete sulfur and nitrogen removal and carbon hydrogenation
is achieved. A significant portion of the 1,050°F+ material in the feed is converted
to < 1050°F, reducing fuel oil production.
CDU
Vacuum distillates
Diesel
Diesel
Crude oil
MHC
Hydrowax
VDU
Vacuum residue
LPG naphtha, natural gas
Rose
H2
HSFO
H2 plant
Bitumen
Reference:
1. “Innovative and cost-effective bottoms upgrading,” METech Conference, February
23, 2017, Dubai, UAE.
Licensor: KBR Inc.
Contact: technologyconsulting@kbr.com
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Upgrading, Heavy Oil—
Thermal gasoil process
Application: The Shell thermal gasoil process is a combined residue and
waxy distillate conversion process. It is an attractive low-cost conversion option
for hydroskimming refineries in gasoil-driven markets, or for complex refineries
with constrained waxy distillate conversion capacity. The typical feedstock is
atmospheric residue, which eliminates the need for an upstream vacuum flasher.
This process features Shell soaker visbreaking technology for residue conversion,
and an integrated recycle heater system for the conversion of waxy distillate.
Thermal conversion of (heavy) vacuum gasoil (HVGO) yields a product slate that
stands comparison with technologies such as hydrocracking when aiming at high
selectivity towards middle distillates, and when considering its far lower investment
cost. These yields and qualities are obtained in a so-called recycle operation, as
selectivity in thermal conversion of (H)VGO to middle distillates depends on the
severity in the cracking furnace, among other things. This severity is expressed as
yield for products boiling below 165°C. The selectivity, defined as the net production of
165°C–350°C gasoil over the net 165°C-minus make, drops off when too high
a conversion is applied because middle distillates are prone to cracking into lighter,
less desirable products. A similar drop in apparent selectivity is observed when the
thermal conversion feedstock contains fractions boiling below 350°C.
Consequently, the process designer should arrive at a compromise between
unit investment and selectivity. Moreover, it should be ensured that no loss of valuable,
unconverted feedstock occurs in the unit.
Description: The preheated atmospheric (or vacuum) residue is charged to the
visbreaker heater (1) and from there to the soaker (2). The conversion takes place
in both the heater and the soaker, and is controlled by the operating temperature
and pressure. The soaker effluent is routed to a cyclone (3). The cyclone overheads
are charged to an atmospheric fractionator (4) to produce the desired products,
including a light waxy distillate. The cyclone and fractionator bottoms are routed
to a vacuum flasher (6), where waxy distillate is recovered. The combined waxy
distillates are fully converted in the distillate heater (5) at elevated pressure.
Operating conditions:
Operating pressure = ~ 20 bara (distillate furnace)
Temperature = 480°C–500°C (distillate furnace)
Gas
Naphtha
Steam
4
3
2
Charge
Gasoil
Waxy
distillate
5
Steam
6
Vacuum flashed
cracked residue
1
Yields: Vary with feed type and product specifications.
Feed atmospheric residue
Middle East
Viscosity, cSt at 100°C
31
Products, wt%
Gas
6.4
Gasoline, ECP 165°C
12.9
Gasoil, ECP 350°C
38.6
Residue, ECP 520°C+
42.1
Advantages: Thermal conversion of (H)VGO yields a product slate that stands
in comparison with other technologies, such as hydrocracking, when aiming
at high selectivity towards middle distillates and when considering its far
lower investment cost.
Economics: The typical investment for a 25-Mbpd unit will be about $3,600/bbl–
$4,200/bbl installed, excluding treating facilities. (Basis: Western Europe, 2014)
Continued 
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Upgrading, Heavy Oil—Thermal gasoil process (cont.)
Utilities: Typical consumption and production for a 25,000-bpd unit, dependent on
configuration and a site’s marginal economic values for steam and fuel:
Electricity, kWh
1,700
Steam (18 bar), tpd
370
C.W. rise (°F or °C), m3/h
95
Fuel (absorbed), MW
30
Installations: Twelve Shell thermal gasoil units have been built. Post startup services
and technical services for existing units are available from Shell Global Solutions.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions
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Upgrading, Heavy Oil—Visbreaking
Off-gas
Application: Visbreaking is a bottom-of-the-barrel upgrading solution that partially
converts atmospheric or vacuum residues using a well-established, non-catalytic
thermal process. Visbreaking reduces the overall quantity of fuel oil produced through
a reduction in viscosity, which reduces the amount of cutter stock required to meet
fuel oil specifications.
Description: Joint licensors Amec Foster Wheeler and UOP offer two types of
visbreaking processes: “coil” and “soaker.” The unit charge is fed into the visbreaker
heater (1), where it is heated to a high temperature, causing partial vaporization and
mild cracking. In a “coil” unit, the reaction is carried out at higher severity and lower
residence time; in contrast, a “soaker” unit uses a specialized soaker drum downstream
of the heater (2) to allow lower severity at a higher residence time. The reaction
products are quenched with gasoil or fractionator bottoms to stop the cracking
reaction. The vapor-liquid mixture enters the fractionator (3) to be separated into gas,
naphtha, gasoil and visbroken residue (tar). Where vacuum gasoil is desired, the tar
may also be vacuum flashed (4) for higher distillate recovery, or for further thermal
cracking of vacuum gasoils (cracking furnace not shown).
Operating conditions: Typical ranges are:
Heater outlet temperature, °F
810–910
Quenched temperature, °F
710–800
Key reaction control parameters are used to vary conversion and product quality,
including heater outlet temperature, injection steam rate and pressure. An increase
in overall severity gives increased conversion and further viscosity reduction, and is
generally limited by bottoms product stability.
Yields:
Feed, source
Arabian Light
Type
Atmospheric residue
API gravity
15.9
Sulfur, wt%
2.95
Conradson carbon residue (CCR), wt%
8.5
Viscosity, cSt at 130°F
150
Viscosity, cSt at 210°F
25
Products, wt%
Gas (C4–)
3.1
Naphtha (C5–330°F)
7.9
Gasoil
14.5 (330°F–600°F)
Visbroken residue
74.5 (600°F+)
Arabian Light
Vacuum residue
7.1
4.0
20.3
30,000
900
2.4
6.0
15.5 (330°F–662°F)
76.1 (662°F+)
Sour water
3
Unestablished naphtha
Vacuum system
2
4
Steam
Steam
Gasoil
Vacuum gasoil
1
Charge
Steam
Fuel oil
Advantages: The Amec Foster Wheeler/UOP visbreaking process configurations
incorporate experience gained from pilot plant studies, commercial operations
and detailed engineering analyses to maximize the yield of on-spec product, while
minimizing capital and operating costs. Our extensive heavy oils expertise is applied to
the design to ensure long runs between unit cleaning.
Economics:
Investment: Visbreaking is a low-cost conversion option to produce incremental
distillates, while simultaneously reducing fuel oil quantity and viscosity.
Utilities: Utility consumption can vary widely depending upon processing
objectives and energy recovery targets. Typical utility consumptions per bbl are listed
here, indicating the visbreaker as a net exporter of steam.
Utilities per barrel of feed
Coil
Soaker
Electricity, kWh
1.23
1.16
Steam (MP), lb produced (net)
7.3
19.5
Cooling water circulation, gal
16.7
13.9
Fuel (consumed), MMBtu
0.14
0.13
Continued 
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Upgrading, Heavy Oil—Visbreaking (cont.)
Development/Delivery: Proprietary equipment or catalyst are unnecessary
in the visbreaking process.
Installations: More than 50 units worldwide.
References:
1. Handbook of Petroleum Refining Processes, 4th Ed., Chapter 11.1, pp. 567–582,
McGraw Hill, 2016.
Licensor: Amec Foster Wheeler/UOP, A Honeywell Company
Websites: www.amecfw.com
www.uop.com/processing-solutions/refining/
Contact: Visbreaking@amecfw.com
2017 REFINING PROCESSES HANDBOOK
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Upgrading, Heavy Oil—Visbreaking
Gas
Application: The Shell soaker visbreaking process is most suitable for reducing
the viscosity of vacuum (and atmospheric) residues in (semi-)complex refineries.
The products are primarily distillates and stable fuel oil. The total fuel oil
production is reduced by decreasing the quantity of cutter stock required.
Optionally, a Shell vacuum flasher may be installed to recover additional gasoil
and vacuum gasoil (VGO) as catalytic cracker or hydrocracker feed from the
cracked residue. The Shell soaker visbreaking technology has also proven to be
a very cost-effective revamp option for existing units.
Description: The preheated vacuum residue is charged to the visbreaker heater
(1) and then to the soaker (2). The conversion takes place in both the heater and
the soaker. The operating temperature and pressure are controlled to reach the
desired conversion level and/or unit capacity. The cracked feed is then charged to
an atmospheric fractionator (3) to produce the desired products (e.g., gas, liquefied
petroleum gas (LPG), naphtha, kerosine, gasoils and cracked residue). If a vacuum
flasher is installed, additional gasoil and VGO are recovered from the cracked residue.
Operating conditions:
Operating pressure = ~ 10 bara
Temperature = 450°C–490°C
Yields: Vary with feed type and product specifications.
Feed
Vacuum residue
Type and source
Middle East
Viscosity, cSt at 100°C
615
Products, wt%
Gas
2.28
Naphtha
4.8
Kerosine + gasoil
13.6
Thermally cracked VGO
23.4
Vacuum flashed cracked residue (liquid coke)
56
Advantages: The Shell soaker visbreaking process has been proven to offer many
benefits that have made it the world’s leading visbreaker technology:
• Up to 15% capital investment savings. Most of the thermal conversion takes
place in the soaker drum. This soaker enables a lower temperature, which
leads to a capital investment savings of up to 15% or more when compared
3
2
Naphtha
Steam
Steam
Gasoil
Vacuum system
Vacuum gasoil
1
Visbroken residue
4
Cutter stock
with conventional coil visbreakers. The lower temperature downstream of the
heater results in a smaller heater and smaller heat-exchange equipment.
• Up to 30% fuel savings. The lower heater outlet temperature results in
a fuel savings of up to 30% compared with conventional coil visbreakers.
• Longer run-lengths. Lower temperatures mean lower heater tube wall
temperatures. This results in reduced coking, extended tube life and
run lengths that are at least three times the run length of conventional
visbreakers. Run lengths of more than 1 yr in a Shell soaker visbreaker are
common compared with run lengths of three to six months for coil visbreaker.
• Enhanced operating flexibility: Soaker visbreakers have both the heater
outlet temperature and the soaker pressure (i.e., reactor residence time)
as variables for process control. This provides more flexibility in the
operation of the visbreaker.
Continued 
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2017 REFINING PROCESSES HANDBOOK
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COMPANY INDEX
Upgrading, Heavy Oil—Visbreaking (cont.)
Investment: The typical investment for a 25,000 bpd unit will be $3,000/bbl–
$3,500/bbl installed, excluding treating facilities. (Basis: Western Europe, 2014)
Utilities: Typical consumption and production for a 25,000 bpd unit, dependent on
configuration and a site’s marginal economic values for steam and fuel:
Electricity, kWh
1,200
Steam (18 bar), tpd
370
C.W. rise (°F or °C), m3/h
90
Fuel (absorbed), MW
25
Development/Delivery: CB&I is the licensing partner
Installations: More than 70 Shell soaker isbreakers have been built. Post startup services
and technical services for existing units are available from Shell Global Solutions.
Licensor: Shell Global Solutions International B.V.
Website: www.shell.com/globalsolutions
Contact: www.shell.com/contact/globalsolutions