Hydroprocessing: Hydrocracking & Hydrotreating
Chapters 7 & 9
Petroleum Refinery Schematic
Gasses
Polymerization Sulfur Plant
Sulfur
Gas
Sat Gas Plant
LPG Alkyl Feed
Alkylation
Butanes
Fuel Gas LPG
Gas Separation & Stabilizer
Isomerization
Polymerization Naphtha Isomerate Alkylate Aviation Gasoline Automotive Gasoline Solvents
Light Naphtha
Reformate Heavy Naphtha
Atmospheric Distillation Naphtha Hydrotreating Naphtha Reforming
Naphtha
Crude Oil
Desalter
Kerosene Cat Naptha
Jet Fuels Kerosene
Hydrocracking
AGO LVGO
Vacuum Distillation
Distillate
Gas Oil Hydrotreating Fluidized Catallytic Cracking
Solvents
Distillate Hydrotreating Treating & Blending
Heating Oils Diesel
HVGO
Cat Distillates Fuel Oil Cycle Oils Residual Fuel Oils
DAO
Solvent Deasphalting
Coker Naphtha
SDA Bottoms
Naphtha
Asphalts
Visbreaking
Vacuum Residuum
Coker Gas Oil
Distillates Fuel Oil Bottoms Lube Oil
Solvent Dewaxing
Lubricant Greases Waxes
Waxes
Coking
Coke
Characteristics of Petroleum Products
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 (NH3) Pyridines & pyrroles are nitrogen containing compounds Nitrogen removal minor in naphtha hydrotreating As the feeds become heavier, denitrogenation becomes 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 hydrotreating catalytic cracking gasoline for sulfur removal yet not saturate olefins, thus maintaining high octane ratings
Saturation of Hydrocarbons
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
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
Sources of Hydrogen Steam-Methane SteamReforming
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
Amount of hydrogen consumed is a function of bonds broken & hydrogen lost with products
Published correlations for hydrogen consumption are weak To some extent, data can be correlated in terms of sulfur level & percent removal
Hydrotreating Chemistry & Hydrogen Consumption
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 hydrogen concentration
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
Ranges from 50 to 250 scf/bbl
Naphtha Hydrotreating Hydrogen Consumption
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
Naphtha Hydrotreating Process
Naphtha Hydrotreating Process
Feed & hydrogen fed to furnace
Outlet vapors about 700F
Vapors passed down-flow over the catalyst bed Outlet cooled & flashed at 100F 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
Naphtha Hydrotreating Process
Typical conditions 700F & 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
Distillate Hydrotreating Process
Hydrogen Consumption
Light distillate hydrotreating (kerosene & jet fuel) requires more hydrogen than naphtha hydrotreating
The two combined usually less than 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, aromatic ring saturation,
Distillate Hydrotreating Process Description
Typical conditions 600F - 800F; 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 Oil Hydrotreating
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 Oil Hydrotreating Process
Gas Oil Hydrotreating 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
Gas Oil Hydrotreating Process
The initial temperature is expected to be of the order of 650F
Hydrogenation highly exothermic care must be taken to avoid runaways
Gas Oil Hydrotreating Process
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 Oil Hydrotreating Process
Gas oil units more expensive because of more intensive 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 Yields see textbook
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 Hydrocracker Feed
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 produce primarily 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 Hydrocracker Products
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
Hydrocracking Chemistry
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
Hydrocracking Chemistry
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
Hydrogen Consumption
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)
Hydrogen Consumption
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
Catalyst Deactivation & Regeneration
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 650F to 750F as a descriptor of mild operations & 750F to 850F for severe operations
Effect of Process Variables on Hydrocracking
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%
Effect of Process Variables on Hydrocracking
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
Single Stage Hydrocracking
Severe Two Stage Hydrocracking
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
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
Single Stage Hydrocracking
Fresh feed, recycle feed, & hydrogen heated in furnace to reactor temperature of about 700F Operating pressure 1,200 psig or more 1,000 scf/bbl or more hydrogen for combined desulfurization & hydrocracking
Single Stage 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
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 1st stage hydrogen recycle loop contains amine system for removal of hydrogen sulfide
Severe Two Stage Hydrocracking
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
Severe Two Stage Hydrocracking
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
