Hydroprocessing fundamentals

 Hydrocracking & Hydrotreating

Use Of Hydrogen in Refineries 

• Hydrogen became available with the advent of platinum catalyst reforming
• In the modern refinery hydrogen is ubiquitous & its use is expected to increase
• Hydrogen is used to produce higher yields & upgrade the quality of fuels produced by the refinery in several ways

Hydroprocessing

• Hydrotreating
» Removal of hetero atoms & saturation of carbon-carbon bonds Nitrogen, oxygen & metals removed Olefinic & aromatic bonds saturated
» Reduce average molecular weight & produce higher yields of fuel products
• Hydrodesulfurization
» Remove sulfur compounds
» Minimum conversion of feed to lighter products
» 10% to 20% conversion
• Hydrocracking
» Severe type of hydrotreating Cracking of carbon-carbon bonds Drastic reduction of molecular weight
» 50%+ conversion

Hydrogen Consumption 

• Amount of hydrogen consumed function of bonds broken & hydrogen lost with products
» Chemical consumption due to hydrogenation reactions
» Hydrogenation reactions are generally exothermic Management of heat of reaction important to safety & operating stability of the unit

Hydrodesulfurization

• Sulfur is converted to hydrogen sulfide (H2S)

» Added  hydrogen breaks carbon-sulfur bonds & saturates remaining hydrocarbon chains
» Creates some light ends
• Heavier distillates make more light ends from breaking more complex sulfur molecules
• Form of sulfur bonds
» Sulfur in naphtha generally mercaptans (thiols) & sulfides
» In heavier feeds, more sulfur as  disulphides & thiopenes

 

Hydrodenitrozation

• Nitrogen is converted to ammonia (N3H )
• Pyridines & pyrroles are nitrogen containing compounds
• Nitrogen removal minor in naphtha hydrotreating
• As the feeds become heavier, denitrogenationbecomes more significant, such as in heavy distillate and gas oil hydrotreating
• Nitrogen removal requires about four times as much hydrogen as the equivalent sulfur removal

Hydrodeoxigenation

• Oxygen converted to water (H2O)
• Examples of oxygen containing compounds are phenols and peroxides
• Like nitrogen removal, oxygen removal is minor in naphtha hydrotreating but significant in heavy distillate hydrotreating

• Oxygen requires about two times as much hydrogen as the equivalent sulfur removal

Other Contaminants

• Organic chlorides are converted to hydrogen chlorides
• These are usually present in small amounts and the hydrogen usage per molecule is similar to desulfurization

Saturation of Hydrocarbons

• Olefins are saturated to form light hydrocarbons
» Consumption stoichiometric with one hydrogen molecule added for each double bond
» Olefins are prevalent in cracked streams such as naphtha streams from a coker or visbreaker, catalytic cracker cycle oil, and catalytic cracker gasoline
» Selective catalysts are available for use in hydrotreatingcatalytic cracking gasoline for sulfur removal yet not saturate olefins, thus maintaining high octane ratings   

• Aromatic rings are hydrogenated to cycloparaffins (naphthenes)
• This is a severe operation and the hydrogen consumption is a strong function of the complexity of the aromatics
• Ring saturation arises in heavy distillate hydrotreating, gas oil hydrotreating, and hydrocracking  

Hydrogen Losses 

• Hydrogen is lost in equilibrium with light gases
• This amount is significant and may double the amount required for sulfur removal
• Hydrogen is absorbed in liquid products
• This is usually small compared to hydrogen used for sulfur removal
• Hydrogen is removed with purge gas used to maintain a high purity of hydrogen as the light ends formed dilute the hydrogen concentration

Characteristics of Hydrotreating

Hydrotreating Trends

• The typical refinery runs at a hydrogen deficit
» With hydroprocessing becoming more prevalent, this deficit will increase
• As hydroprocessing progresses in severity, the hydrogen demands increase dramatically
• Trend in more hydroprocessing is driven by: several factors:
» Heavier & higher sulfur crudes
» Reduction in demand for heavy fuel oil
» Increased use of hydrodesulfurization for low sulfur fuels
» More complete protection of FCCU catalysts
» Demand for high quality coke

Sources of Hydrogen — Catalytic Reformer

• The most important source of hydrogen for the refiner
• Typically 90 vol% from a continuously regenerated reformer & 80 vol% from semi-continuously regenerated reformer
• Approximately 50 psig

Typical Path of Hydrogen Usage

• Sulfur removed in an amine unit
• Fed directly to the hydrotreaters for desulfurization of naphtha & distillates, kerosene, jet fuel, diesel & home heating oil
» Desulfurization consumes 100 to 200 scf/barrel feed, about half the hydrogen available from the reformer
• Remainder used for gas oil hydrotreating & hydrocracking

» Require additional hydrogen
• When hydrogen concentration has been depleted, the residue is either used for fuel gas or sent to a unit for hydrogen recovery
» Recovery operations often done by a third party 

Sources of Hydrogen — FCCU Offgas

• Typically 5 vol% hydrogen with methane, ethane & propane
• Several methods for recovery — can be combined

»Cryogenic
» Pressure swing adsorption
» Membrane separation 

Sources of Hydrogen — Steam-Methane  Reforming 

• Most common method of manufacturing hydrogen
• Methane, ethane, or heavy components reformed to hydrogen, carbon dioxide, &  water in a series of three reactions
» methane catalytically reacts to form hydrogen and carbon monoxide in an exothermic reaction
» Carbon monoxide “shifted” with steam to form additional hydrogen & carbon dioxide in an endothermic reaction
» Carbon dioxide removed using one of several absorption processes
» Trace amounts of carbon monoxide & carbon dioxide removed by exothermically reacting with hydrogen to form methane & water
• Hydrogen purity typically 90 to 95 vol% 

Sources of Hydrogen — Synthesis Gas

• Partial oxidation (gasification) of heavy resid feed
• ‘Water-gas’ shift technology from asphalts, resids, & other very heavy liquid or coal slurry
• Synthesis gas will contain equal volumes of carbon monoxide & hydrogen with about 5 vol% carbon dioxide & smaller volumes of methane, nitrogen, water & sulfur
• Hydrogen recovered normally by:
» pressure swing adsorption
» membrane separation
• Advantages & disadvantages
» More expensive than steam reforming
» Can destroy a variety of polluted streams & low quality by product streams

Purpose of Hydrotreating

• Attractive for feeds with small concentrations of aromatics & contaminants
• Remove contaminants & break aromatic bonds
» Sulfur removed as hydrogen sulfide
» Metals deposited on catalysts
• Breaks aromatic bonds
» Lowers average molecular weight
» Produces higher yields of fuel products
• Minimum cracking
• Products suitable for further processing: reforming, catalytic cracking, hydrocracking.  

Development of Hydrotreating

• In the 1940s the catalytic reformer produced hydrogen
• This hydrogen was used for distillate hydrotreating
» Primarily to remove sulfur
» Ring saturation also improved kerosene smoke point & diesel Cetane Number
• Over two dozen hydrotreating processes are offered by licensors.

Pretreatment

• Arsenic is a serious catalyst poison & must be removed
» Found in some crude fractions
» Some process schemes have a sacrificial catalyst trap ahead of reactor
• May need extra hydrogen & intra-bed cooling for olefins
» Saturation catalyst bed ahead of the reactor for acetylene & diene saturation

 Hydrotreating Chemistry & Hydrogen 

Consumption 

• Amount of hydrogen consumed is a function of bonds broken & hydrogen lost with roducts
» Published correlations for hydrogen consumption are weak
» To some extent, data can be correlated in terms of sulfur level & percent removal
• Chemical consumption due to hydrogenation reactions
• Hydrogenation reactions are generally exothermic
» Management of the heat of reaction important to safety & operating stability of unit

Other Hydrogen Losses

• Hydrogen is lost in equilibrium with light gases
» Amount is significant & may double amount required for sulfur removal
• Hydrogen absorbed in liquid products
» Usually small compared to sulfur removal needs
• Hydrogen removed with purge gas
» Used to maintain a high purity of hydrogen — light ends dilute the hydrogen concentration
» Usually small compared to sulfur removal needs
• Cracking reactions of carbon-carbon bonds minimal in hydrotreating, even during aromatic saturation

Metals Removal 

• Metals deposited directly on the catalysts
• Excess metals reduce catalyst activity & promote dehydrogenation
» Produce coke & hydrogen
• Metals removal important in gas oil hydrotreating. 

Hydrotreating Catalysts

Two types

» Cobalt molybdenum catalysts preferred for desulfurization & olefin saturation Require less hydrogen for mild operation

» Nickel molybdenum used for nitrogen removal &aromatic saturation.

General Effects of Process Variables

• Reactor inlet temperature & pressure

» Increasing temperature increases hydrogenation but decreases the number of active catalyst sites

» Temperature control is used to offset the decline in catalyst activity

» Increasing pressure increases hydrogen partial pressure & increases the severity of hydrogenation

• Recycle hydrogen

» Require high concentration of hydrogen at reactor outlet Hydrogen amount is much more than stoichiometric High concentrations required to prevent coke laydown & poisoning of catalyst Particularly true for the heavier distillates containing resins and asphaltenes

• Purge hydrogen

» Removes light ends & helps maintain high hydrogenconcentration

Increasing Severity 

Naphtha hydrotreating Distillate (light and heavy) hydrotreating Gas oil hydrotreating

Naphtha Hydrotreating

• Naphtha hydrotreated primarily for sulfur removal
» Sulfur present as mercaptans (RSH), sulfides (R2S), disulfides (RSSR), & thiophenes (ring structures)
• Straight run gasoline may be added to naphtha prior to hydrotreating
» Combining offers advantages at the crude unit
» Calls for a larger hydrotreater & a splitter to separate Pentane/hexane overhead to isomerization Bottoms to reformer
• Cobalt molybdenum on alumina most common catalyst
» Activated by converting the oxides on the alumina to sulfides — simple pretreatment process

Naphtha Hydrotreating Hydrogen

Consumption

• Ranges from 50 to 250 scf/bbl
» For desulfurization containing up to 1 wt% sulfur — 70 to 100 scf/bbl Higher sulfur levels increase hydrogen consumption proportionately
» Significant nitrogen & sulfur removal — 250 scf/bbl
• This is chemical hydrogen consumption
» Add for mechanical loss & loss with the light hydrocarbon vapors

• Feed & hydrogen fed to furnace
» Outlet vapors about 700°F
• Vapors passed down-flow over the catalyst bed
• Outlet cooled & flashed at 100°F to separate light ends
» Exchanged with feed (for heat integration)
» Final exchange with cooling water
» Single stage flash adequate
» Bulk of flash gas recycled
• Flashed liquid fed to stripper for removal of light ends, hydrogen sulfide, and sour water

• Typical conditions — 700°F & 200 psig
» Temperature can vary with catalyst activity & stringency of treatment
• Liquid hourly space velocity about 2
» Fixed bed reactor design parameter
• Hydrogen recycle about 2,000 scf/bbl
• Stripper overhead vapor to saturates gas plant
» Recovery of light hydrocarbons & removal H2S
• Precision fractionator must be added to process both light straight run & naphtha
» Pentane/hexane overhead to isomerization
» Bottoms to reformer

Distillate Hydrotreating

• In general, all liquid distillate streams contain sulfur compounds that must be removed
• Saturation of olefins in diesel to improve the cetane number

Hydrogen Consumption

• Light distillate hydrotreating (kerosene & jet fuel) requires more hydrogen than naphtha hydrotreating
» The two combined usually less than ½ reformer's production
• Heavy distillate (diesel) hydrotreating consumption quite variable
» Can consume considerable quantities of hydrogen at higher severity
• Hydrogen consumption & operating pressure are a function of the stream being treated, the degree of sulfur & nitrogen removal, olefin saturation, aromaticring saturation, …

Distillate Hydrotreating Process Description

• Typical conditions — 600°F - 800°F; 300 psig & greater
» Modest temperature rise since reactions are exothermic
• Hydrogen recycle rate starts at 2,000 scf/bbl; consumption 100 to 400 scf/bbl
• Conditions highly dependent upon feedstock
» Distillate (jet fuel & diesel) with 85% - 95% sulfur removal — 300 psig & hydrogen consumption of 200 -300 scf/bbl
» Saturation of diesel for cetane number improvement —over 800 scf/bbl hydrogen & up to 1,000 psig

Distillate Hydrotreating Process

• Hydrogenation at the high  pressure produces small amounts of naphtha from hydrocracking
» Required to get at the imbedded sulfur
» Diesel hydrotreater stabilizer will have an upper sidestream draw producing the naphtha which is recycled to motor gasoline processing

Gas OilHydrotreating

• Catalytic cracker feedstocks (atmospheric gas oil, light vacuum gas oil, solvent deasphalting gas oil) hydrotreated severely
»Sulfur removal
» Opening of aromatic rings
» Removal of heavy metals
• Desulfurization of gas oil can be achieved with a relatively modest decomposition of structures
• Gas oils can be contaminated with resins & asphaltenes
» Deposited in hydrotreater
» Require catalyst replacement with a shorter run length  than determined by deactivation
» Guard chamber may be installed to prolong bed life
• Nickel molybdenum catalyst system for severe hydrotreating

Gas OilHydrotreating Process

• Normally requires two reactors of two beds
» Temperature rise from initial hydrogenation requires  liquid quench
• Effluent from the second reactor is flashed in two stages
» High-pressure flash provides recycle hydrogen gas
» Low-pressure flash separates light ends for hydrogen sulfide recovery Low-pressure flash liquid is treated gas oil & sent to cat cracker

• The initial temperature is expected to be of the order of 650°F
» Hydrogenation highly exothermic — care must be taken to avoid runaways

• Hydrogen partial pressure related to ring saturation & in turn to the amount of sulfur converted to hydrogen sulfide
» For low ring saturation 300 psig may be sufficient
» 1,200 psig will to 25% ring saturation & somewhat less than 95% sulfur removal
» Pressures as high as 1,500 psig can achieve saturation of 30% of aromatic rings
• Hydrogen absorption of 300 scf/bbl could give about 80% sulfur removal & only require 300 psig
» No ring saturation at these mild conditions

Gas OilHydrotreating Process

• Gas oil units more expensive because of moreintensive hydrogenation
» Quench
» Multi-stage flash
» More complex strippers

Hydrocracking

• Purpose: process gas oil to break carbon-carbon bonds of large aromatic compounds & remove contaminants
» Hydrogenation (addition of hydrogen)
» Cracking (carbon-carbon scission) of aromatic bonds
• Typically creates distillate range products, not gasoline range products

Development of Hydrocracking

• I.G. Farben in Germany developed the original process
• Exxon obtained the technology in the 1930s to increase product yields from crude oil
» Discovery of the East Texas field swamped the country with a surplus of crude & delayed  adoption of this technology

Gas Oil HydrocrackerFeed

• Hydrocracking does a better job of processing aromatic rings without coking than catalytic cracking
» Hydrogen used to hydrogenate polynuclear aromatics (PNAs)
» Reduces frequency of aromatic condensation
• Hydrocracking not as attractive as delayed coking for resids high in resins, asphaltenes & heteroatom compounds
» Heteroatoms & metals prevalent in resins & asphaltenes poison hydroprocessing catalysts
» High concentrations of resins & asphaltenes will still ultimately coke
• Feeds limited to a Conradson Carbon Number (CCR) of 8 wt%
• Feeds require high pressures & large amounts of hydrogen

Hydrocracking Feeds

• Typical feeds
» Cat cracker “cycle oil” Highly aromatic with sulfur, small ring & polynuclear aromatics, catalyst fines; usually has high viscosity Hydrocracked to form high yields of jet fuel, kerosene, diesel, & heating oil
» Gas oils from visbreaker Aromatic
» Gas oil from the delayed coker Aromatic, olefinic, with sulfur
• Usually more economical to route atmospheric & vacuum gas oils to the cat  cracker to produceprimarily gasoline & some diesel

Hydrocracking Feeds

• Feedstock selection is much more sophisticated than mere determination of CCR
» Distribution of aromatic, naphthenic, & paraffinic structures important

Gas Oil HydrocrackerProducts

•Hydrocracking primarily to make distillates
» In US hydrocracking normally a specialized operation used to optimize catalytic cracker operation
» In US cat cracking preferred to make gasoline from heavier fractions
•Hydrocracking capacity is only about 8% of the crude distillation capacity
» Not all refineries have hydrocrackers
•Intent is to minimize the production of heavy fuel oil
» Light ends are approximately 5% of the feed.
» Middle distillates (kerosene, jet fuel, diesel, heating oil) still contain uncracked polynuclear  aromatics
•All liquid fractions are low in sulfur & olefins

Hydrocracking Chemistry

• Cracking reactions
» Saturated paraffins cracked to form lower molecular weight olefins & paraffins
» Side chains cracked off small ring aromatics (SRA) & cycloparaffins (naphthenes)
» Side chains cracked off resins & asphaltenes leaving thermally stable polynuclear aromatics (PNAs) But condensation (dehydrogenation) also occurs if not limited by hydrogenation

Hydrogenation reactions

» Exothermic giving off heat
» Hydrogen inserted to saturate newly formed molecule from aromatic cracking
» Olefins are saturated to form light hydrocarbons, especially butane
» Aromatic rings hydrogenated to cycloparaffins(naphthenes)
» Carbon-carbon bonds cleaved to open aromatic & cycloparaffins (naphthenes) rings
» Heteroatoms form hydrogen sulfide, ammonia, water,hydrogen chloride

• Isomerization Reactions
» Isomerization provides branching of alkyl groups of paraffins and opening of naphthenic rings
• Condensation Reactions.
» Suppressed by hydrogen

Hydrogen Consumption 

Carbon bonds with heteroatoms broken & saturated
» Creates light ends Heavier distillates make more light ends from breaking more complex molecules
» Sulfur converted to hydrogen sulfide
» Nitrogen converted to ammonia
» Oxygen converted to water
» Organic chlorides converted to hydrogen chloride

• Saturation of carbon-carbon bonds
» Olefins saturated to form light hydrocarbons. Consumption stoichiometric — one hydrogen
molecule added for each double bond
» Aromatic rings hydrogenated to cycloparaffins (naphthenes). Severe operation — hydrogen consumption strong function of complexity of the aromatics
• Isomerization reactions generally not present
• Metals deposited directly on the catalysts
» Excess metals reduce catalyst activity & promote dehydrogenation (produces coke & hydrogen)

• Have cracking of carbon-carbon bonds Severe operation — hydrogen consumption strong function of complexity of the aromatics
• Hydrogen lost in mixture with products
» Equilibrium with light gases Significant — may double amount required for sulfur removal
» Absorbed in liquid products Usually small compared to hydrogen used for sulfur removal
» Lost with purge gas

Hydrocracking Catalysts

• Hydrocracking catalysts generally a crystalline silica alumina base with a rare earth metal deposited in the lattice.
» Acid function is provided by the silica alumina base
» Chlorides not required in catalyst formulation
• Feed stock must first be hydrotreated
» Catalysts susceptible to sulfur poisoning if hydrogen sulfide is present in large quantities
» Catalysts not affected by ammonia
» Sometimes necessary to remove moisture to protect the crystalline structure of catalyst
» Hydrocracking with a metallic hydrogenation function is sensitive to metal contamination

Catalyst Deactivation & Regeneration

• Catalysts deactivate & coke does form even with hydrogen present
» Hydrocrackers require periodic regeneration of the fixed bed catalyst systems
• Channeling caused by coke accumulation a major concern
» Can create hot spots that can lead to temperature runaways

• Ebullient beds for better heat and mass transfer
» Bed of pelletized catalyst expanded by the upflow fluids in the reactor
» Improves contact & minimizes channeling
» Downflow draft tube with an internal pump used to facilitate a circulation pattern
• Continuous withdrawal of catalyst from an expanded circulating bed for regeneration.
» For use in hydrocracking whole crude or long resid

Effect of Process Variables on Hydrocracking

• Crackability of feed & desired yield of products determine operating severity
• Operating severity
» Catalyst
» Space velocity
» Total pressure
» Hydrogen partial pressure.
• Severe operations needed significantly reduce molecular weight of the feed & increase the  hydrogen:carbon ratio in products

Effect of Process Variables on Hydrocracking

•Severity
» Mild operation for diesel or fuel oil from heavy gas oil
» Severe operation for kerosene or naphtha from a light gas oil
•Temperature
» Temperature not used to increase severity
» Temperature adjusted to offset decline in catalyst activity
» Consider 650°F to 750°F as a descriptor of mild operations & 750°F to 850°F for severe operations

• Pressure & Hydrogen Consumption
» Lower operating pressure: 1,200 psig; hydrogen consumption 1,000 - 2,000 scf/bbl
» More severe operations to destroy heavier components & open rings: 2,000 psig; 2,000 to 3,000 scf/bbl or more
• These hydrogen consumptions primarily for the hydrocracking reactions with low sulfur removal & olefin/aromatic saturation
» Mild or severe hydrocracking with extensive desulfurization or olefin/aromatic saturation will increase hydrogen consumption, possibly by 25%

• Hydrogen amount is much more than stoichiometric
• Require high concentration of hydrogen at reactor outlet
» High concentrations are required to prevent coke laydown on catalyst and poisoning the  catalyst.
» Purge hydrogen
» Make-up hydrogen

Hydrocracking Process Description

• Single stage or two stage processes
»Unit size
» Severity of the operation Products desired Nature of the feedstock feed pretreating for  contaminant removal
• Two extremes
» Mild one stage hydrocracking system
» Severe two stage operation

Single Stage Hydrocracking

• Simplest hydrocracker — single reactor combining modest desulfurization with hydrocracking of gas oil to distillates
» Hydrogen sulfide must be relatively low & not be a problem for these catalysts
» Desulfurization catalyst in the top bed & sulfur insensitive hydrocracking catalysts in lower bed
• Olefin saturation can be a problem in terms of heat release
» Hydrogen quench
» Additional quench between hydrocracking catalyst beds

• Fresh feed, recycle feed, & hydrogen heated in furnace to reactor temperature of about 700°F
• Operating pressure 1,200 psig or more
• 1,000 scf/bbl or more hydrogen for combined desulfurization & hydrocracking

• Product separation
» Reactor product is flashed to recycle hydrogen at as high a pressure as possible Minimize recompression horsepower
» Gas from low pressure (50 to 75 psig) flash to gas plant
• Liquid from flash fractionated at naphtha overhead conditions
» straight run gasoline
» naphtha suitable for reforming
» distillates either jet fuel/kerosene or diesel/heating oil
» bottoms for recycle Some bottoms may be purged to fuel oil, which would reduce severity

Two Stage Alternative

• May use separate reactors with desulfurization & olefin saturation in 1st reactor & hydrocracking in 2nd reactor
»1st reactor removes contaminants & saturates aromatics
» Can also do part of the hydrogenation conversion
• Effluent from 1st reactor sent to fractionator — fractionator bottoms sent to the 2nd stage  hydrocracking reactor
• May need a separate internal hydrogen sulfide removal

Severe Two Stage Hydrocracking

• Required for hydrocracking feed stocks containing appreciable amounts  of sulfur, olefins, simple aromatics, & polynuclear aromatics
» Light cycle oil
»Gas oil
» Coker gas oil
• Separate hydrotreating with hydrogen sulfide removal followed by hydrocracking — requires
multiple beds
» Different catalyst systems in the reactor beds
» Amount of hydrogen sulfide generated sufficient to poison 2nd stage catalysts stage hydrogen recycle loop contains amine  1st system for removal of hydrogen sulfide

•Feed is first desulfurized at high pressure
» Uses 500 scf/bbl of hydrogen over a conventional hydrodesulfurization catalyst system
•Provision for hydrogen quench
» Olefin saturation in the top bed
» Aromatics saturation in the lower beds
•Recycle hydrogen is amine treated to remove hydrogen sulfide
•Hydrotreating & hydrocracking reactors have separate hydrogen recycle systems
» Each has a high pressure flash for hydrogen recycle & low pressure flash for removing light  ends
» Light ends stripped to assure complete removal from naphtha

• Hydrogen flash done at as high a pressure as feasible to minimize recompression — low pressure flash is set by system to process flash gas
• Severe operations lead to more extensive cracking & light ends production
• Hydrogen consumption for hydrocracking is of the order of 1,500 to 3,000 scf/bbl
» Additional hydrogen consumption for sulfur & nitrogen removal, olefin saturation, & ring saturation in 1st stage