Hydrogenation (2) - Copy

1

Introduction

Mechanism of Catalytic Hydrogenation

Hydrogen Production from HC

Factors Affecting Hydrogenation

PSA Technology for Hydrogen Purification

Hydrogenation in Refining Processes

Hydrogenation in Gas Processes

Ch.E-305 Muhammad Asif Akhtar 2

Hydrogenation is the addition of hydrogen to a

chemical compound.

Generally, the process involves elevated

temperature and relatively high pressure in the

presence of a catalyst.


Hydrogenation may be either destructive or non-

destructive.

In the former case, hydrocarbon chains are ruptured

(cracked) and hydrogen is added where the breaks have

occurred.

In the latter, hydrogen is added to a molecule that is

unsaturated with respect to hydrogen. In either case, the

resulting molecules are highly stable.


1. Besides saturating double bonds, hydrogenation

can be used to eliminate other elements from a

molecule. These elements include:

Oxygen

Nitrogen

Halogens

Sulfur


APPLICATION

2. Cracking (thermal decomposition) in the presence of hydrogen is

particularly effective in desulfurizing high-boiling petroleum fractions,

thereby producing lower-boiling and higher-quality products

REACTION TYPE ILLUSTRATION ∆HR

kJ per standard cubic meter of consumed H2

† R = alkyl

M = Fe, Ni

A = metals-adsorbing material


3. Oils have been

hydrogenated for

many decades, to

prolong their shelf life

and make the oils

more stable.



Saturation of olefins is irreversible and the saturation

of aromatics is reversible.

Hydrogenation is generally carried out in the presence of a catalyst and under elevated temperature and pressure. Noble metals, nickel, copper, and various metal oxide combinations are the common catalysts.

The catalyst binds both the H2 and the unsaturated substrate and facilitates their union.

Pd and Pt are poisoned by sulfur and can only be used in low-H2S environments

Gaseous hydrogen is the usual hydrogenating agent.




12 Ch.E-305 Muhammad Asif Akhtar

H H C C

A

B

X

Y H H


H

C C A

B

X

Y

H H H


H

H H H

C C

A

B

X Y


H

H H H

C C

A

B

X Y


H H

H

C C

A

B

X Y

H



Hydrogen use has become more widespread in refineries,

hydrogen production has moved from the status of a high-

technology specialty operation to an integral feature of

most refineries. This has been made necessary by the

increase in hydrotreating and hydrocracking, including the

treatment of progressively heavier feedstocks.

Steam reforming is the dominant method for hydrogen

production. This is usually combined with pressure-swing

adsorption (PSA) to purify the hydrogen to greater than 99

vol %.


The best feedstocks for steam reforming are light, saturated, and low in sulfur; this includes natural gas, refinery gas, LPG, and light naphtha. These feeds can be converted to hydrogen at high thermal efficiency and low capital cost.

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 Technip in several modern plants with multiple feedstock flexibility.


Natural gas is the most common hydrogen plant feed, since it meets all

the requirements for reformer feed and is low in cost.

A typical pipeline natural gas contains over 90 percent C1 and C2, with

only a few percent of C3 and heavier hydrocarbons.

It may contain traces of CO2, with often significant amounts of N2.

The N2 will affect the purity of the product hydrogen: It can be

removed in the PSA unit if required, but at increased cost. Purification

of natural gas, before reforming, is usually relatively simple.

Traces of sulfur must be removed to avoid poisoning the reformer

catalyst, but the sulfur content is low and generally consists of H2S

plus some mercaptans.

Zinc oxide, often in combination with hydrogenation, is usually

adequate.



Refinery gas, containing a substantial amount of hydrogen, can be an attractive steam reformer feedstock.

Since it is produced as a by-product, it may be available at low cost.

Processing of refinery gas will depend on its composition, particularly the levels of olefins and of propane and heavier hydrocarbons.

Olefins can cause problems by forming coke in the reformer. They are converted to saturated compounds in the hydrogenator, giving off heat. This can be a problem if the olefin concentration is higher than about 5 percent, since the hydrogenator will overheat.


Liquid feeds, either LPG or naphtha, can be

attractive feedstocks where prices are

favorable. Liquid feeds can also provide backup feed, if there is a risk of

natural gas curtailments.


The generic flowsheet consists of


Feed Pre-treatment

Pre reforming (Optional)

Steam-HC Reforming

Shift Conversion and

Hydrogen Purification By Pressure Swing Adsorption (PSA).





Hydrogen Production By Steam

Reforming/PSA.


Steam Reforming/Wet Scrubbing

Feed pre-treatment normally involves removal of sulfur,

chlorine and other catalyst poisons after preheating to

350 – 400°C.


The treated feed gas mixed with process steam is

reformed in a fired reformer (with adiadatic pre-

reformer upstream, if used) after necessary super-

heating. 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 carbon monoxide (CO) is further converted

to hydrogen. Process condensate resulting from heat

recovery and cooling is separated and generally reused in

the steam system after necessary treatment.

The gas flows to the PSA unit that provides high-purity

hydrogen product (up to < 1 ppm CO) at near inlet

pressures.






Typical utility requirements for a 50 million SCFD hydrogen

plant feeding natural gas are as follows (no compression is

required).

Technip has been involved in over 240 hydrogen plants

worldwide.

Licensor: Technip.


Previous Lecture Review


41

Absorption is not adsorption

absorption: accumulation within (not on) a solid


Profitability for hydrogen and ammonia plants depends heavily on the efficiency and reliability of carbon dioxide (CO2) removal from process gas.

Over the last 30 years, several innovations have evolved regarding CO2-removal units. New methods have dramatically increased

• Absorption efficiency

• Reduced CO2 slip to a few parts per million by volume (ppmv),

• Lowered energy requirements for CO2 regeneration and mitigated corrosion of plant equipment.



K2CO3 + CO2 + H2O = 2KHCO3

K2CO3 + H2S = KHS + KHCO3

Reactions:



Ch.E-305 Muhammad Asif Akhtar





52

PSA

Technology

for Hydrogen

Purification


The PSA process produces a hydrogen stream of four- nines (99.99%) purity.

It separates carbon monoxide, carbon dioxide and unconverted hydrocarbons.

A bank of adsorbers operates in a cycle where the adsorbers are rotated through a higher-pressure adsorption portion, followed by a pressure reduction, which allows the contaminants to be released from the adsorber.

The hydrogen gas passes through the adsorber as almost-pure hydrogen



55

A PSA installation consists of four major parts:

Adsorber vessels made from carbon steel and filled

with adsorbent

Valves and instrumentation

Control system which is normally located in a remote

control room

Mixing drum



57

A complete pressure-swing cycle consists of the

following five basic steps:

1. Adsorption

2. Cocurrent depressurisation

3. Countercurrent depressurisation

4. Purge at low pressure

5. Repressurisation
























Production of any purity hydrogen, typically 90% to +99.9999 mole%.

Impurities efficiently removed include:

N2, CO, CH4, CO2, H2O, Ar, O2, C2–C8+, CH3OH, NH3, H2S and organic sulfur compounds.

The technology can also be used to:

Purify CH4, CO2, He, N2 and Cl;

Remove CO2;

Adjust synthesis gas stream composition ratios and separate nitrogen from hydrocarbons.


Steam reformer (at any point after the reformer),

Catalytic reformer net gas

Refinery purge streams

Gasification offgases

Ammonia plant purge gases (before or after the NH3 waterwash)

Ethylene plant offgases

Partial oxidation gases

Styrene plant offgases

Ethanol plant purge gases

Coke-oven gas

Cryogenic purification offgases or other H2 sources.

Feed pressures up to 1,000 psig have been commercially demonstrated.


Recovery of H2 varies between 60% and 90%,

depending on composition, pressure levels and

product requirements.

Typical temperatures are 60°F to 120°F.

Purity can be +99.9999 mole%.


Purification is based on advanced pressure swing adsorption (PSA) technology.

Purified H2 is delivered at essentially feed pressure, and impurities are removed at a lower pressure.

Polybed PSA units contain 4 to 16 adsorber vessels. One or more vessels are on the adsorption step, while the others are in various stages of regeneration.

Single-train Polybed PSA units can have product capacities over 200 million scfd.


Operation is automatic with pushbutton startup and

shutdown.

After startup, the unit will produce H2 in two to four hours.

Onstream factors in excess of 99.8% relative to unplanned

shutdowns are typical.

Turndown capability is typically 50% but can be even

lower where required.

The units are built compactly with plot plans ranging from

12 ft x 25 ft to 60 ft x 120 ft.


Units are skid-mounted and modular to minimize installation costs.

Material for piping and vessels is carbon steel.

Control can be via a local or remote-mounted control panel or by integration into the refinery’s computer control system.

Units are designed for outdoor, unattended operation and require no utilities other than small quantities of instrument air and power for instrumentation.



More than 700 units are in operation or under construction,

including the world’s first 16-bed system, and the world’s

largest single-train system.

Licensor

UOP LLC.




FEED: Natural gas, refinery off gases, LPG, naphtha or mixtures.

PRODUCT:

High-purity H2 (typically >99.9%), carbon monoxide

(CO), carbon dioxide (CO2), high-pressure steam and/or

electricity may be produced as separate creditable by-

product.



The feed is desulfurized (1), mixed with steam and

converted to synthesis gas in steam reformer (2) over a

nickel-containing catalyst at 20 – 40 bar pressure and

outlet temperatures of 800 –900°C.

The Uhde steam reformer features a well-proven top-fired

design with tubes made of centrifugally cast alloy steel and

a unique proprietary “cold” outlet manifold system for

enhanced reliability.


A further speciality of Uhde’s H2 plant design is an optional bi-sectional steam system for the environmentally friendly full recovery of process condensate and production of high-pressure export steam (3) with a proven process gas cooler design.

The Uhde steam reformer concept also includes a fully pre-fabricated and modularized convection bank design to further enhance the plant quality and minimize construction risks.

The final process stages are the adiabatic CO shift (4) and a pressure swing adsorption unit (5) to obtain high-purity H2.


Process options include:

Feed evaporation

Adiabatic feed pre-reforming and/or

HT/LT shift to process, for example, heavier feeds

and/or to optimize feed/fuel consumption and steam

production.

Uhde’s design allows combining maximized process heat

recovery and optimized energy efficiency with

operational safety and reliability.


The Uhde reformer design is particularly advantageous for

the construction and reliable operation of large-scale

reformers with H2 capacities up to 220,000 Nm3/ h (197

MMscfd) in single-train configurations.

Uhde offers either standard or tailor-made designs and

applies either customer or own design standards.


Depending on the individual plant concept, the typical

consumption figure for natural gas-based plants (feed + fuel

– steam) can be as low as 3.13 Gcal /1,000 Nm3 (333

MMBtu/MMscf) or 3.09 (329) with pre-reforming.


Recently, Uhde has successfully commissioned large-scale H2 plants for

SINCOR C.A., Venezuela (2 x 100,000 Nm3/ h or 2 x 90 MMscfd)

Shell Canada Ltd., Canada (2 x 130,000 Nm3/ h or 2 x 115 MMscfd)

and is presently executing four H2 projects, including H2 plants for

Neste Oil Oyj (formerly Fortum Oil Oy)

Finland (1 x 155,000 Nm³/ h or 140 MMscfd) and

Shell Canada Ltd., Canada, (1 x 150,000 Nm³/ h or 135 MMscfd).

More than 60 Uhde reformers have been designed and constructed worldwide.




To produce methanol from natural or associated gas

feedstocks using two-step reforming followed by low-

pressure synthesis. This technology is well suited for world-

scale plants to modify ammonia capacity into methanol

production.


Methanol or methyl alcohol (CH3OH) is a colourless

liquid with a boiling point of 65oC.

Methanol will mix with a wide variety of organic

liquids as well as with with water and accordingly it is

often used as a solvent for domestic and industrial

applications.

Methanol is the raw material for many chemicals,

formaldehyde, dimethyl terephphalate, methylamines

and methyl halides, methyl methacrylate, acetic acid,

gasoline etc.


In recent years methanol has also been used for other

markets such as production of DME (Di-methyl-ether)

and olefins by the so-called methanol-to-olefins process

(MTO) or as blendstock for motor fuels.

The annual production of methanol exceeds 40 million

tons and continues to grow by 4% per year.


The production of methanol from coal is increasing in locations where natural gas is not available or expensive such as in China. However, most methanol is produced from natural gas.

Several new plants have been constructed in areas where natural gas is available and cheap such as in the Middle East.

There is little doubt that (cheap) natural gas will remain the predominant feed for methanol production for many years to come.


The capacity of methanol plants has increased

significantly only during the last decade. In 1996 a

world scale methanol plant with a capacity of 2500

MTPD was started up in Norway. Today several

plants are in operation with the double of this

capacity.


All commercial methanol technologies feature three

process sections and a utility section as listed below:

Synthesis gas preparation (reforming)

Methanol synthesis

Methanol purification

Utilities


In the design of a methanol plant the three process sections may be considered independently, and the technology may be selected and optimized separately for each section.

The normal criteria for the selection of technology are capital cost and plant efficiency.

The synthesis gas preparation and compression typically accounts for about 60% of the investment, and almost all energy is consumed in this process section.

Therefore, the selection of reforming technology is of paramount importance.


Important properties of the synthesis gas are the CO to

CO2 ratio and the concentration of inerts.

A high CO to CO2 ratio will increase the reaction rate

and the achievable per pass conversion. In addition, the

formation of water will decrease, reducing the catalyst

deactivation rate.

High concentration of inerts will lower the partial

pressure of the active reactants. Inerts in the methanol

synthesis are typically methane, argon and nitrogen.


Several reforming technologies are available for

producing synthesis gas:

One-step reforming with fired tubular reforming

Two-step reforming

Autothermal reforming (ATR)


The synthesis gas is produced by tubular steam

reforming alone (without the use of oxygen). This

concept was traditionally dominating.

Today it is mainly considered for up to 2,500 MTPD

plants and for cases where CO2 is contained in the

natural gas or available at low cost from other

sources.


The synthesis gas produced by one-step reforming

will typically contain a surplus of hydrogen of about

40%. This hydrogen is carried unreacted through the

synthesis section only to be purged and used as

reformer fuel.

The addition of CO2 permits optimization of the

synthesis gas composition for methanol production.

CO2 constitutes a less expensive feedstock, and

CO2 emission to the environment is reduced.


The application of CO2 reforming results in a very

energy efficient plant.

The energy consumption is 5–10% less than that of a

conventional plant . A 3,030 MTPD methanol plant

based on CO2 reforming was started up in Iran in

2004.



Methanol — Steam-methane Reforming

Licensor: Haldor Topsøe A/S.

This process features a combination of fired tubular reforming (primary reforming) followed by oxygen-fired adiabatic reforming (secondary reforming).

The secondary reformer requires that the primary reformer is operated with a significant leakage of unconverted methane (methane slip).

Typically 35 to 45% of the reforming reaction occurs in the tubular reformer, the rest in the oxygen-fired reformer.

As a consequence the tubular reformer is operated at low S/C ratio, low temperature and high pressure.


These conditions lead to a reduction in the

transferred duty by about 60% and in the reformer

tube weight by 75 to 80% compared to one-step

reforming.



Methanol— Two-step Reforming

Licensor: Haldor Topsøe A/S.

The gas feedstock is compressed (if required), desulfurized(1) and sent to a saturator (2) where process steam is generated. All process condensate is reused in the saturator resulting in a lower water requirement.

The mixture of natural gas and steam is preheated and sent to the primary reformer (3). Exit gas from the primary reformer goes directly to an oxygen-blown secondary reformer (4).

The oxygen amount and the balance between primary and secondary reformer are adjusted so that an almost stoichiometric synthesis gas with a low inert content is obtained. The primary reformer is relatively small and the reforming section operates at about 35 kg/cm2g.


The flue gas’ heat content preheats reformer feed.

Likewise, the heat content of the process gas is used to produce superheated high-pressure steam (5), boiler feedwater preheating, preheating process condensate going to the saturator and reboiling in the distillation section (6).

After final cooling by air or cooling water, the synthesis gas is compressed in a one-stage compressor (7) and sent to the synthesis loop (8), comprised of three adiabatic reactors with heat exchangers between the reactors. Reaction heat from the loop is used to heat saturator water.


Steam provides additional heat for the saturator system.

Effluent from the last reactor is cooled by preheating feed

to the first reactor, by air or water cooling.

Raw methanol is separated and sent directly to the

distillation (6), featuring a very efficient three-column

layout.

Recycle gas is sent to the recirculator compressor (9) after

a small purge to remove inert compound buildup.


Topsøe supplies a complete range of catalysts that can be used

in the methanol plant. Total energy consumption for this

process scheme is about 7.0 Gcal/ton including energy for

oxygen production.


Total investments, including an oxygen plant, are

approximately 10% lower for large plants than for a

conventional plant based on straight steam reforming.


The two-step reforming lay-out was first used in a

2400 MTPD methanol plant in Norway. This plant

was started up in 1997. A 5000 MTPD plant based

on similar technology was started up in Saudi Arabia

in 2008.

Licensor:

Haldor Topsøe A/S.


ATR features a stand-alone, oxygen-fired reformer.

The autothermal reformer design features a burner, a

combustion zone, and a catalyst bed in a refractory

lined pressure vessel .



The burner provides mixing of the feed and the oxidant.

In the combustion zone, the feed and oxygen react.

The catalyst bed brings the steam reforming and shift conversion reactions to equilibrium in the synthesis gas and makes the operation of the ATR soot-free.

The catalyst loading is optimized with respect to activity and particle shape and size to ensure low pressure drop and compact reactor design.


Methanol synthesis gas is characterised by the

stoichiometric ratio (H2 – CO2) / (CO + CO2), often

referred to as the module M. A module of 2 defines a

stoichiometric synthesis gas for formation of

methanol.

The synthesis gas produced by autothermal reforming

is rich in carbon monoxide, resulting in high reactivity

of the gas. The synthesis gas has a module of 1.7 to 1.8

and is thus deficient in hydrogen.


The module must be adjusted to a value of about 2 before the synthesis gas is suitable for methanol production. The adjustment can be done either

By removing carbon dioxide from the synthesis gas or By recovering hydrogen from the synthesis loop purge gas and recycling the recovered hydrogen to the synthesis gas .

Adjustment by hydrogen recovery can be done either by a membrane or a PSA unit. Both concepts are well proven in the industry.



Methanol production by ATR at low S/C ratio. Adjustment

of synthesis gas composition by hydrogen recovery and

recycle.


Natural gas is preheated and desulfurized.

After desulfurization, the gas is saturated with a mixture of preheated process water from the distillation section and process condensate in the saturator.

The gas is further preheated and mixed with steam as required for the pre-reforming process.

In the pre-reformer, the gas is converted to H2, CO2 and CH4.

Final preheating of the gas is achieved in the fired heater.

In the autothermal reformer, the gas is reformed with steam and O2.


The product gas contains H2, CO, CO2 and a small amount

of unconverted CH4 and inerts together with under

composed steam.

The reformed gas leaving the autothermal reformer

represents a considerable amount of heat, which is

recovered as HP steam for preheating energy and energy for

providing heat for the reboilers in the distillation section.

The reformed gas is mixed with hydrogen from the pressure

swing adsorption (PSA) unit to adjust the synthesis gas

composition.


Synthesis gas is pressurized to 5 –10 MPa by a single-casing synthesis gas compressor and is mixed with recycle gas from the synthesis loop

This gas mixture is preheated in the heater in the gas-cooled methanol reactor.

In the Lurgi water-cooled methanol reactor, the catalyst is fixed in vertical tubes surrounded by boiling water.

The reaction occurs under almost isothermal condition, which ensures a high conversion and eliminates the danger of catalyst damage from excessive temperature.

Exact reaction temperature control is done by pressure control of the steam drum generating HP steam


The “preconverted” gas is routed to the shell side of the gas

cooled methanol reactor, which is filled with catalyst.

The final conversion to methanol is achieved at reduced

temperatures along the optimum reaction route. The reactor

outlet gas is cooled to about 40°C to separate methanol and

water from the gases by preheating BFW and recycle gas.

Condensed raw methanol is separated from the unreacted

gas and routed to the distillation unit.


The major portion of the gas is recycled back to the

synthesis reactors to achieve a high overall conversion. The

excellent performance of the Lurgi combined converter

(LCC) methanol synthesis reduces the recycle ratio to about

2.

A small portion of the recycle gas is withdrawn as purge

gas to lessen inerts accumulation in the loop.


In the energy-saving three-column distillation section,

low-boiling and high-boiling byproducts are removed.

Pure methanol is routed to the tank farm, and the

process water is preheated in the fired heater and used

as makeup water for the saturator.


Energy consumption for a stand-alone plant, including

utilities and oxygen plant, is about 30 GJ/metric ton of

methanol.

Total installed cost for a 5,000-mtpd plant including

utilities and oxygen plant is about US$350 million,

depending on location.


Thirty-five methanol plants have been built using

Lurgi’s Low-Pressure methanol technology.

One Mega Methanol plant is in operation, two are

under construction and three Mega Methanol contracts

have been awarded with capacities up to 6,750 mtpd of

methanol.

Licensor

Lurgi AG.


In the methanol synthesis conversion of synthesis gas into

raw methanol takes place. Raw methanol is a mixture of

methanol, a small amount of water, dissolved gases, and

traces of by-products.

Typical byproducts include DME, higher alcohols, and

minor amounts of acids and aldehydes.

The methanol synthesis catalyst and process are highly

selective. A selectivity of 99.9% is not uncommon.



The conversion of hydrogen and carbon oxides to

methanol is described by the following reactions:

The methanol synthesis is exothermic and the

maximum conversion is obtained at low temperature

and high pressure.

A challenge in the design of a methanol synthesis is to

remove the heat of reaction efficiently and

economically - i.e. at high temperature - and at the

same time to equilibrate the synthesis reaction at low

temperature, ensuring high conversion per pass.


Different designs have been used:

Quench reactor

Adiabatic reactors in series

Boiling water reactors (BWR)


It consists of a number of adiabatic catalyst beds

installed in series in one pressure shell. In practice, up

to five catalyst beds have been used. The reactor feed is

split into several fractions and distributed to the

synthesis reactor between the individual catalyst beds.

The quench reactor design is today considered

obsolete and not suitable for large capacity plants.


A synthesis loop with normally comprises a number (2-

4) of fixed bed reactors placed in series with cooling

between the reactors. The cooling may be by preheat of

high pressure boiler feed water, generation of medium

pressure steam, and/or by preheat of feed to the first

reactor.

The adiabatic reactor system features good economy of

scale. Mechanical simplicity contributes to low

investment cost. The design can be scaled up to single-

line capacities of 10,000 MTPD or more.


The BWR is in principle a shell and tube heat exchanger

with catalyst on the tube side.

Cooling of the reactor is provided by circulating boiling

water on the shell side.

By controlling the pressure of the circulating boiling

water the reaction temperature is controlled and

optimized. The steam produced may be used as process

steam, either direct or via a falling film saturator.


The isothermal nature of the BWR gives a high

conversion compared to the amount of catalyst installed.

However, to ensure a proper reaction rate the reactor will

operate at intermediate temperatures - say between

240ºC and 260ºC - and consequently the recycle ratio

may still be significant.

Complex mechanical design of the BWR results in

relatively high investment cost and limits the maximum

size of the reactors.

Thus, for very large scale plants several boiling water

reactors must be installed in parallel.


It is the last section of the plant. The design of this unit

depends on the desired end product. Grade AA methanol

requires removal of essentially all water and by products

while the requirements for fuel grade methanol are more

relaxed.


HYDROGENATION IN REFINNING

AND GAS PROCESSES



REFINERY LAYOUT











Hydrocracking is a two-stage process combining catalytic cracking and hydrogenation, wherein heavier feedstock are cracked in the presence of hydrogen to produce more desirable products.

The process employs high pressure, high temperature, a catalyst, and hydrogen.

Hydrocracking is used for feedstock that are difficult to process by either catalytic cracking or reforming, since these feedstock are characterized usually by a high polycyclic aromatic content and/or high concentrations of the two principal catalyst poisons, sulfur and nitrogen compounds.


Demand for gasoline and diesel is increasing, while the

demand for heavy-oils, such as fuel-oil is declining.

Refiners are therefore taking more steps to convert

heavy oils into lighter distillates.

Hydrocracking can significantly improve refining

margins by upgrading low-value products into higher-

value, high-demand products.


Typical hydrocracking feedstocks include heavy atmospheric and vacuum gas oils, and catalytically or thermally cracked gas oils.

These products are converted to lower molecular weight products, primarly naphtha or distillates.

Sulphur, nitrogen and oxygen removal and olefin saturation occur simultaneously with the hydrocracking reaction. Typical reactor operating conditions are

280 – 475 °C

35 – 215 bar

depending on the feedstock and final products desired. The reactions consume hydrogen and are highly exothermic.


Single stage, once through

hydrocracker

Single stage hydrocracker

with recycle

Two stage hydrocracker


This configuration uses only one reactor and any uncracked

residual hydrocarbon oil from the bottom of the reaction

product fractionation (distillation) tower is not recycled for

further cracking.

For single stage hydrocracking, either the feedstock must first

be hydrotreated to remove ammonia and hydrogen sulfide or

the catalyst used in the single reactor must be capable of

both hydrotreating and hydrocracking.


This is the most commonly used configuration.

The uncracked residual hydrocarbon oil from the bottom

of reaction product fractionation tower is recycled back

into the single reactor for further cracking.

Again, for single stage hydrocracking, either the

feedstock must first be hydrotreated to remove ammonia

and hydrogen sulfide or the catalyst used in the single

reactor must be capable of both hydrotreating and

hydrocracking.


This configuration uses two reactors and the residual

hydrocarbon oil from the bottom of reaction product

fractionation tower is recycled back into the second reactor for

further cracking.

The first stage reactor accomplishes both hydrotreating and

hydrocracking, the second stage reactor feed is virtually free

of ammonia and hydrogen sulfide. This permits the use of

high performance noble metal (palladium, platinum) catalysts

which are susceptible to poisoning by sulfur or nitrogen

compounds.



Presentation1.pptx

Basically, catalytic hydrocracking involves three primary chemical processes:

Cracking of high-boiling, high molecular weight hydrocarbons found in petroleum crude oil into lower-boiling, lower molecular weight hydrocarbons.

Hydrogenating unsaturated hydrocarbons (whether present in the original feedstock or formed during the cracking of the high-boiling, high molecular weight feedstock hydrocarbons) to obtain saturated hydrocarbons usually referred to as paraffins or alkanes.

Hydrogenating any sulfur, nitrogen or oxygen compounds in the original feedstock into gaseous hydrogen sulfide, ammonia and water.


Reaction 1:

Addition of hydrogen to aromatics converts them into hydrogenated rings.

These are then readily cracked using acid catalysts.

Reaction 2:

Acid catalyst cracking opens paraffinic rings, breaks larger paraffins into

smaller pieces and creates double bonds.

Reaction 3:

Addition of hydrogen to olefinic double bonds to obtain paraffins.

Reaction 4:

Isomerization of branched and straight-chain paraffins.


Hydrocracking catalysts consist of active metals on solid, acidic supports and have a dual function, specifically a cracking function and a hydrogenation function.

The cracking function is provided by the acid catalyst support and the hydrogenation function is provided by the metals.

The solid acidic support consists of amorphous oxides such as silica-alumina, crystalline zeolite or a mixture of amorphous oxides and crystalline zeolite.

Cracking and isomerization reactions (reactions 2 and 4 above) take place on the acidic support. Metals provide the hydrogenation reactions (reactions 1 and 3 above).


The metals that provide the hydrogenation

functions can be the noble

metals palladium and platinum or the base metals

(i.e.,non-noble

metals) molybdenum, tungsten, cobalt or nickel.

Catalyst cycle life has a major impact on the

economics of hydrocracking. Cycles can be as

short as 1 year or as long as 5 years. Two years are

typical.




A versatile family of premium distillates technologies

is used to meet all current and possible future premium

diesel upgrading requirements.

Ultra-deep hydrodesulfurization (UDHDS) process can

produce distillate products with sulfur levels below 10

wppm from a wide range of distillate feedstocks.


High volume yield of ultra-low-sulfur distillate is

produced. Cetane and API gravity uplift, together

with the reduction of polyaromatics to less than 6

wt% or as low as 2 wt%, can be economically

achieved.


The UDHDS reactor and catalyst technology is offered through Akzo

Nobel Catalysts bv.

A single-stage, single-reactor process incorporates proprietary high-

performance distribution and quench internals.

Feed and combined recycle and makeup gas are preheated and contact

the catalyst in a downflow, cocurrent fixed-bed reactor.

The reactor effluent is flashed in a high- and a low-pressure separator.

An amine-absorber tower is used to remove H2S from the recycle gas. In

the example shown, a steam stripper is used for final product recovery.

The UDHDS technology is equally applicable to revamp and

grassroots applications.


Over 60 distillate upgrading units have applied the

Akzo Nobel ultra-deep HDS technology.

Twenty-five of these applications produce, or will

produce, <10ppm sulfur, using UDHDS technology.

Licensor: Akzo Nobel Catalysts bv.



Reduction of the sulfur, nitrogen and metals content

of naphthas, kerosines, diesel or gas oil streams.

Products

Low-sulfur products for sale or additional processing.



Single or multibed catalytic treatment of hydrocarbon liquids in the presence of hydrogen converts organic sulfur to hydrogen sulfide and organic nitrogen to ammonia.

Naphtha treating normally occurs in the vapor phase, and heavier oils usually operate in mixed-phase. Multiple beds may be placed in a single reactor shell for purposes of redistribution and/or inter bed quenching for heat removal.

Hydrogen rich gas is usually recycled to the reactor(s) (1) to maintain adequate hyrogen- to-feed ratio. Depending on the sulfur level in the feed, H2S may be scrubbed from the recycle gas.

Product stripping is done with either a reboiler or with steam. Catalysts are cobalt-molybdenum, nickel-molybdenum, nickel-tungsten or a combination of the three.


550°F to 750°F and

400 psig to 1,500 psig reactor conditions.

Yields:

Depend on feed characteristics and product

specifications. Recovery of desired product almost

always exceeds 98.5 wt% and usually exceeds 99%.


Licensor: CB&I Howe-Baker Process and Technology.



Topsøe 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.

Products:

Ultra-low-sulfur diesel fuel, and clean feedstocks for FCC

and hydrocracker units.



Topsøe’s hydrotreating process design incorporates our

industrially proven high-activity TK catalysts with

optimized graded-bed loading and high-performance,

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 economic way.


Typical operating pressures range from

20 to 80 barg (300 to 1,200 psig)

and typical operating temperatures range from

320°C to 400°C (600°F to 750°F).


More than 40 Topsøe hydrotreating units for the

various applications above are in operation or in the

design phase.

Licensor:

Haldor Topsøe A/S.


