U.S. patent application number 14/044744 was filed with the patent office on 2015-04-02 for apparatuses and methods for cracking hydrocarbons.
This patent application is currently assigned to UOP LLC. The applicant listed for this patent is UOP LLC. Invention is credited to Miladin Crnkovic, Richard A. Johnson, II, Thomas William Lorsbach, Paolo Palmas.
Application Number | 20150090636 14/044744 |
Document ID | / |
Family ID | 52739037 |
Filed Date | 2015-04-02 |
United States Patent
Application |
20150090636 |
Kind Code |
A1 |
Lorsbach; Thomas William ;
et al. |
April 2, 2015 |
APPARATUSES AND METHODS FOR CRACKING HYDROCARBONS
Abstract
Methods and apparatuses are provided for cracking a hydrocarbon.
The method includes contacting a hydrocarbon feed stream with a
cracking catalyst at cracking conditions to produce a reactor
effluent and a spent catalyst. The spent catalyst is transferred to
a regenerator, where it is regenerated by contact with an oxygen
supply gas at regeneration conditions to produce a regenerated
catalyst. The regenerated catalyst is fluidized for catalyst
movement with a replacement gas having less than 1 mass percent
oxygen gas
Inventors: |
Lorsbach; Thomas William;
(Austin, TX) ; Palmas; Paolo; (Des Plaines,
IL) ; Johnson, II; Richard A.; (Algonquin, IL)
; Crnkovic; Miladin; (Schaumburg, IL) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
UOP LLC |
Des Plaines |
IL |
US |
|
|
Assignee: |
UOP LLC
Des Plaines
IL
|
Family ID: |
52739037 |
Appl. No.: |
14/044744 |
Filed: |
October 2, 2013 |
Current U.S.
Class: |
208/113 ;
422/144 |
Current CPC
Class: |
Y02P 30/446 20151101;
Y02P 30/40 20151101; C10G 11/182 20130101 |
Class at
Publication: |
208/113 ;
422/144 |
International
Class: |
C10G 11/02 20060101
C10G011/02 |
Claims
1. A method of cracking hydrocarbons, the method comprising the
steps of: contacting a hydrocarbon feed stream with a cracking
catalyst at cracking conditions in a reactor to produce a reactor
effluent and a spent catalyst; transferring the spent catalyst from
the reactor to a regenerator; regenerating the spent catalyst in
the regenerator to produce regenerated catalyst by contacting the
spent catalyst with an oxygen supply gas at regeneration
conditions; and fluidizing the regenerated catalyst in the
regenerator with a replacement gas for catalyst movement, wherein
the replacement gas comprises less than 1 mass percent oxygen
gas.
2. The method of claim 1 wherein fluidizing the regenerated
catalyst further comprises fluidizing the regenerated catalyst with
the replacement gas for catalyst movement, wherein the replacement
gas comprises more than 95 mass percent steam.
3. The method of claim 1 wherein fluidizing the regenerated
catalyst further comprises fluidizing the regenerated catalyst with
the replacement gas for catalyst movement, wherein the replacement
gas comprises more than 95 mass percent nitrogen.
4. The method of claim 1 wherein fluidizing the regenerated
catalyst further comprises fluidizing the regenerated catalyst with
the replacement gas for catalyst movement, wherein the replacement
gas comprises a mixture of steam and nitrogen, and wherein the
mixture of steam and nitrogen comprises more than 95 mass percent
steam and nitrogen.
5. The method of claim 1 wherein fluidizing the regenerated
catalyst further comprises: cooling the regenerated catalyst in a
catalyst cooler, wherein the replacement gas fluidizes the
regenerated catalyst within the catalyst cooler.
6. The method of claim 1 further comprising: transferring the
regenerated catalyst from the regenerator to the reactor in a
regenerated catalyst transfer line; and fluidizing the regenerated
catalyst in the regenerated catalyst transfer line with the
replacement gas.
7. The method of claim 6 further comprising: collecting the
regenerated catalyst in a regenerator dense bed prior to
transferring the regenerated catalyst from the regenerator to the
reactor; and fluidizing the regenerated catalyst in the regenerator
dense bed with the replacement gas.
8. The method of claim 1 wherein regenerating the spent catalyst
further comprises producing a combustion gas, the method further
comprising: stripping the combustion gas from the regenerated
catalyst by passing the replacement gas through the regenerated
catalyst.
9. The method of claim 8 further comprising: venting the combustion
gas from the regenerator in a combustion gas vent line.
10. The method of claim 1 wherein contacting the hydrocarbon feed
stream with the cracking catalyst further comprises contacting the
hydrocarbon feed stream with the cracking catalyst wherein the
hydrocarbon feed stream comprises petroleum hydrocarbons.
11. A method of cracking hydrocarbons, the method comprising the
steps of: combusting coke from a spent catalyst to produce a
regenerated catalyst and a combustion gas by contacting the spent
catalyst with an oxygen supply gas at regeneration conditions;
stripping the combustion gas from the regenerated catalyst by
passing a replacement gas through the regenerated catalyst, wherein
the replacement gas comprises less than 1 mass percent oxygen gas;
and cracking the hydrocarbons by combining the hydrocarbons with
the regenerated catalyst at cracking conditions to produce the
spent catalyst.
12. The method of claim 11 wherein stripping the combustion gas
from the regenerated catalyst further comprises: collecting the
regenerated catalyst in a regenerator dense bed; and fluidizing the
regenerated catalyst in the regenerator dense bed with the
replacement gas.
13. The method of claim 11 wherein stripping the combustion gas
from the regenerated catalyst further comprises stripping the
combustion gas from the regenerated catalyst by passing the
replacement gas through the regenerated catalyst, wherein the
replacement gas comprises more than 95 mass percent steam.
14. The method of claim 11 wherein stripping the combustion gas
from the regenerated catalyst further comprises stripping the
combustion gas from the regenerated catalyst by passing the
replacement gas through the regenerated catalyst, wherein the
replacement gas comprises more than 95 mass percent nitrogen.
15. The method of claim 11 wherein stripping the combustion gas
from the regenerated catalyst further comprises stripping the
combustion gas from the regenerated catalyst by passing the
replacement gas through the regenerated catalyst, wherein the
replacement gas comprises a mixture of steam and nitrogen, and
wherein the mixture of steam and nitrogen comprises more than 95
mass percent steam and nitrogen.
16. The method of claim 11 further comprising: cooling the
regenerated catalyst in a catalyst cooler prior to cracking the
hydrocarbons by combining the hydrocarbons with the regenerated
catalyst, wherein the replacement gas fluidizes the regenerated
catalyst within the catalyst cooler.
17. The method of claim 11 further comprising: transferring the
regenerated catalyst from a regenerator to a reactor in a
regenerated catalyst transfer line; and fluidizing the regenerated
catalyst in the regenerated catalyst transfer line with the
replacement gas.
18. The method of claim 11 wherein cracking the hydrocarbons by
combining the hydrocarbons with the regenerated catalyst further
comprises cracking the hydrocarbons by combining the hydrocarbons
with the regenerated catalyst wherein the hydrocarbons comprise
petroleum hydrocarbons.
19. The method of claim 11 further comprising: venting the
combustion gas from a regenerator in a combustion gas vent
line.
20. An apparatus for cracking hydrocarbons comprising: a reactor; a
regenerator; a spent catalyst transfer line configured to transfer
a spent catalyst from the reactor to the regenerator; an oxygen
supply gas inlet coupled to the regenerator, wherein the oxygen
supply gas inlet is configured to provide an oxygen supply gas to
convert the spent catalyst into a regenerated catalyst, and to
transfer the regenerated catalyst into a regenerator separator area
of the regenerator; and a fluidizing gas inlet coupled to the
regenerator, wherein the fluidizing gas inlet is configured to
provide a fluidizing gas different than the oxygen supply gas to
the regenerator separator area.
Description
TECHNICAL FIELD
[0001] The present disclosure generally relates to apparatuses and
methods for cracking hydrocarbons, and more particularly relates to
apparatuses and methods for cracking hydrocarbons and recovering
products with fewer oxygen containing compounds present in the
recovered products.
BACKGROUND
[0002] Fluid catalytic cracking (FCC) is primarily used to convert
high boiling, high molecular weight hydrocarbons from petroleum
into lower boiling, lower molecular weight compounds. The lower
molecular weight compounds include gasoline, olefinic compounds,
liquid petroleum gas (LPG), diesel fuel, etc. An FCC unit uses a
catalyst that is repeatedly deactivated and regenerated in a
reactor and a regenerator, respectively. Air is used to burn coke
off of the deactivated catalyst in the regeneration process, and
produces combustion gases such as carbon dioxide, carbon monoxide,
and water. Oxygen and combustion gases are carried with the
regenerated catalyst and flow through the FCC unit.
[0003] The FCC unit uses a fractionator to separate the various
compounds produced into different fractions, where the fractionator
overhead stream includes the lightest compounds with the lowest
boiling points. Combustion gases, excess oxygen, and inert gases
are included in the overhead stream. The overhead stream is
processed in a gas concentration unit to remove and recover sulfur
and prepare products with low boiling points, such a liquid
petroleum gas or fuel gas. Excess inert gases increase the total
quantity of gas processed by the gas concentration unit, and
oxygen, carbon dioxide (CO.sub.2), and carbon monoxide (CO)
increase corrosion on the gas concentration unit equipment. Excess
oxygen, CO.sub.2, and CO also increase the use of amines in the
sulfur removal process, which increases costs.
[0004] Accordingly, it is desirable to develop methods and
apparatuses for reducing excess oxygen, CO.sub.2, and CO in the FCC
unit to improve operations of the gas concentration unit. In
addition, it is desirable to develop methods and apparatuses for
reducing the inert gas load on the gas concentration unit.
Furthermore, other desirable features and characteristics of the
present embodiment will become apparent from the subsequent
detailed description and the appended claims, taken in conjunction
with the accompanying drawing and this background.
BRIEF SUMMARY
[0005] A method is provided for cracking hydrocarbons. A
hydrocarbon feed stream is contacted with a cracking catalyst at
cracking conditions to produce a reactor effluent and a spent
catalyst. The spent catalyst is transferred to a regenerator, where
it is regenerated by contact with an oxygen supply gas at
regeneration conditions to produce a regenerated catalyst. The
regenerated catalyst is fluidized for catalyst movement with a
replacement gas having less than 1 mass percent oxygen gas.
[0006] Another method is provided for cracking hydrocarbons. Coke
is combusted from a spent catalyst to produce a regenerated
catalyst and a combustion gas by contacting the spent catalyst with
an oxygen supply gas at regeneration conditions. The combustion gas
is stripped from the regenerated catalyst by passing a replacement
gas with less than 1 mass percent oxygen gas through the
regenerated catalyst. Hydrocarbons are cracked by combining the
hydrocarbons with the regenerated catalyst at cracking conditions,
which also produces the spent catalyst.
[0007] An apparatus is also provided for cracking hydrocarbons. The
apparatus includes a reactor and a regenerator, with a spent
catalyst transfer line configured to transfer spent catalyst from
the reactor to the regenerator. An oxygen supply gas inlet is
coupled to the regenerator and configured to provide an oxygen
supply gas to convert the spent catalyst into a regenerated
catalyst, and to transfer the regenerated catalyst into a
regenerator separation area. A fluidizing gas inlet is coupled to
the regenerator, and configured to provide a fluidizing gas to the
regenerator separator area. A replacement gas source is coupled to
the fluidizing gas inlet, and configured to provide a replacement
gas with less than 1 mass percent oxygen gas.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] Various embodiments will hereinafter be described in
conjunction with the FIGURE, which is a schematic diagram of an
exemplary embodiment of an apparatus and method for cracking
hydrocarbons.
DETAILED DESCRIPTION
[0009] The following detailed description is merely exemplary in
nature and is not intended to limit the application or uses of the
embodiment described. Furthermore, there is no intention to be
bound by any theory presented in the preceding technical field,
background, brief summary, or the following detailed
description.
[0010] Apparatuses and methods for cracking hydrocarbons and
recovering products with fewer oxygen-containing compound present
in the recovered products are provided herein. An FCC unit has a
reactor and a regenerator working in concert. Regenerated catalyst
is transferred to the reactor where it is contacted with a
hydrocarbon feedstock to crack the hydrocarbons into smaller
hydrocarbon molecules. During the cracking reaction, coke forms on
the surface of the catalyst, which in turn becomes deactivated as
the coke builds up. In a conventional FCC unit, the deactivated
catalyst is transferred to a regenerator where air is used to burn
the coke off of the catalyst to regenerate it. The regenerated
catalyst is then transferred back to the reactor to be contacted
with the hydrocarbon feedstock again. The cracked hydrocarbons are
fractionated to separate various fractions, and combustion gases,
oxygen, and inert gases are included in the fractionator overhead
stream. The catalyst is fluidized throughout the process, including
fluidization for catalyst movement or transfers, and air is
typically used as the fluidizing gas in the regenerator. Oxygen is
needed to combust the coke, but air increases the oxygen in the
fractionator overhead stream. As noted above, the oxygen and oxygen
containing compounds in the overhead stream increase equipment
corrosion and increase the quantity of amines used in a sulfur
removal process. In contract, the methods and apparatuses
contemplated herein use a replacement gas that is low in gaseous
oxygen for catalyst fluidization in non-combustion processes in the
regenerator, and this reduces the oxygen in the fractionator
overhead stream. The replacement gas also strips the regenerated
catalyst of entrained combustion gases, such as CO.sub.2 and CO,
prior to transfer to the reactor.
[0011] In accordance with an exemplary embodiment, a fluid
catalytic cracking (FCC) unit 10 includes a reactor 20 and a
regenerator 40, as illustrated in the FIGURE. A hydrocarbon feed
stream 12 is introduced to the reactor 20. In an exemplary
embodiment, the hydrocarbons in the hydrocarbon feed stream 12 are
petroleum hydrocarbons, often relatively heavy hydrocarbons that
include the portion of crude oil with an initial boiling point of
about 340 degrees centigrade (.degree. C.) or higher, at
atmospheric pressure. The crude oil is fractionated, and heavier
fractions are often used as the hydrocarbon feed stream 12 to
produce products with higher commercial demand. In some
embodiments, the hydrocarbons have an average molecular weight of
about 200 to about 600 Daltons or higher. Various process streams
can be used as the hydrocarbon feed stream 12, including but not
limited to heavy gas oil, vacuum gas oil, reduced crude, and resid.
The hydrocarbons are primarily made of hydrogen and carbon, but
many hydrocarbon feed streams 12 also include some oxygen,
nitrogen, sulfur, and heavy metals.
[0012] The hydrocarbon feed stream 12 is contacted with a cracking
catalyst 14. Any suitable cracking catalyst 14 can be used as is
known in the art. Suitable cracking catalysts 14 for use herein
include high activity crystalline alumina silicate and/or zeolite,
which are dispersed in a porous inorganic carrier material such as
silica, aluminum, zirconium, or clay. An exemplary embodiment of a
cracking catalyst 14 includes crystalline zeolite as the primary
active component, a matrix, a binder, and a filler. The zeolite
ranges from about 10 to 50 weight percent of the catalyst, and is a
silica and alumina tetrahedral with a lattice structure that limits
the size range of hydrocarbon molecules to enter the lattice. The
matrix component includes amorphous alumina, and the binder and
filler provide physical strength and integrity. Silica sol or
alumina sol are used as the binder and kaolin clay is used as the
filler.
[0013] The hydrocarbons from the hydrocarbon feed stream 12 are
discharged into a low portion of a riser 22, where the riser 22 is
the primary reaction zone of the reactor 20. The hydrocarbons are
vaporized and carried up through the riser 22 with fluidized
cracking catalyst 14. A lift gas 24 is used to aid in fluidizing
and carrying the hydrocarbons and cracking catalyst 14 up through
the riser 22, where the lift gas 24 may include steam and/or light
hydrocarbons. The hydrocarbon feed stream 12 is typically
introduced into the riser 22 as a liquid, and the hydrocarbons are
vaporized by heat from the hot cracking catalyst 14 and from the
lift gas 24, where the hot cracking catalyst 14 is often a
regenerated catalyst 18. The vaporized hydrocarbons and cracking
catalyst 14 rise up through the riser 22, where the hydrocarbons
are contacted with the cracking catalyst 14 and cracked into
smaller hydrocarbons.
[0014] In an exemplary embodiment, the hydrocarbons and cracking
catalyst 14 in the riser 22 have a typical flowing density of about
50 kilograms per cubic meter (3 pounds per cubic foot) and an
average superficial velocity of about 3 to about 30 meters per
second (9 to 100 feet per second) to produce a riser residence time
of between about 0.5 to 10 seconds. Cracking conditions in the
riser 22 range from about 400.degree. C. to about 650.degree. C.
(750 degrees Fahrenheit (.degree. F.) to 1,200.degree. F.) and a
pressure from about 100 kilo Pascals gauge (kPa) to about 250 kPa
(15 pounds per square inch gauge (PSIG) to about 35 PSIG). The lift
gas 24 and the vaporized hydrocarbons fluidize the cracking
catalyst 14, and the fluidized catalyst and vapors are accelerated
in the lower riser to between about 1 and about 8 meters per second
(about 3 to about 26 feet per second). The cracking catalyst 14 to
hydrocarbon weight ratio in the riser 22 is about 4 to about 12,
and the temperature of the hydrocarbon feed stream 12 when
introduced to the riser 22 is about 150.degree. C. to about
450.degree. C. (300.degree. F. to 850.degree. F.).
[0015] The vaporized hydrocarbons and cracking catalyst 14 travel
up the riser 22 to a riser termination device 26, where the
cracking catalyst 14 is distributed in a reactor separation area
28. Once the cracking catalyst 14 is covered in coke from the
reaction with the hydrocarbons, it becomes spent catalyst 16 that
falls downward and collects at the bottom of the reactor separation
area 28. The vaporized, and now cracked, hydrocarbons pass through
a reactor cyclone 30 to further separate the gaseous hydrocarbons
from the spent catalyst 16, and the hydrocarbons are discharged
from the reactor 20 in a reactor effluent 32. The hydrocarbon
cracking reaction is endothermic, and heat is required to vaporize
the hydrocarbons from the hydrocarbon feed stream 12. In some
embodiments, the heat is primarily supplied by the hot cracking
catalyst 14 that enters the riser 22 at an elevated temperature. In
many embodiments, the hot cracking catalyst 14 is regenerated
catalyst 18, but fresh cracking catalyst 14 can also be used. About
70 percent of the heat is used to vaporize the hydrocarbon feed
stream 12 with about 30 percent used to drive the endothermic
cracking reaction, depending on the operating conditions and the
composition of the hydrocarbon feed stream 12.
[0016] The reactor effluent 32 is fed into a fractionation zone 70
that separates the reactor effluent 32 into various fractions based
on the volatility of the hydrocarbon molecules. A wide variety of
operating conditions can be used in the fractionation zone 70 in
different embodiments, such as maintaining a pressure from about
100 kPa to about 200 kPa (14 PSIG to 30 PSIG) and a temperature of
about 80.degree. C. to about 140.degree. C. (180.degree. F. to
280.degree. F.) at the overhead. The fractionation zone 70 includes
one or more distillation columns, and the operating conditions can
vary. The lightest compounds with the lowest vapor pressures and
boiling points are discharged from the fractionation zone 70 in an
overhead stream 72. A bottoms stream 74 includes the heaviest
compounds with the highest boiling points, and the fractionation
zone 70 may produce one or more side cut streams with various
intermediate products, such as light naphtha, heavy naphtha, light
cycle oil, and heavy cycle oil. Water, such as from condensed
steam, is discharged in a side stream referred to herein as a sour
water stream 76, where the sour water stream 76 also includes a
hydrocarbon fraction. The water is typically split and separated
from the hydrocarbon fraction after exiting the fractionation zone
70.
[0017] The overhead stream 72 includes non-condensable gases, such
as oxygen (O.sub.2), nitrogen (N.sub.2), carbon dioxide (CO.sub.2),
and carbon monoxide (CO), various sulfur-containing compounds such
as mercaptans, and low boiling hydrocarbons such as hydrocarbons
with four carbon atoms or less (C4-). In an exemplary embodiment,
the overhead stream 72 has a boiling point of less than about
35.degree. C. (95.degree. F.) at atmospheric pressure. The overhead
stream 72 is directed to a gas concentration unit 78 that separates
the hydrocarbons into a liquid petroleum gas (LPG) stream 80 and a
fuel gas stream 82. In various embodiments, the gas concentration
unit 78 includes compressors, absorbers, strippers, and other
processing equipment, as is known in the art. The fuel gas stream
82 is further treated in a sulfur removal unit 84, which uses
amine-treating or other technologies, and the removed sulfur is
sent to a sulfur recovery plant 86.
[0018] Inert gases, such as N.sub.2, increase the burden on the gas
concentration unit 78 because of the increased volume of material
processed. Carbon monoxide, CO.sub.2 and O.sub.2 typically increase
corrosion and wear and tear on the equipment, reduce reliability of
the operation, and increase the amount of amine used in the sulfur
removal processes. For example, the CO.sub.2 is converted to
carboxylic acids that can make heat stable salts in the sulfur
removal unit 84. In contrast to conventional methods and
apparatuses, by using the methods and apparatuses contemplated
herein oxygen containing compounds in the overhead stream 72, such
as CO.sub.2, CO, and O.sub.2, are reduced by operations in the
regenerator 40. Reducing the use of oxygen-containing gases leads
to fewer oxygen containing compounds in the overhead stream 72.
Also, the use of gases that do not exit the fractionation zone 70
in the overhead stream 72, such as steam that exits as liquid
water, reduces the total burden on the gas concentration unit
78.
[0019] In this regard, spent catalyst 16 is fed to the regenerator
40 in a spent catalyst transfer line 42, and enters a coke
combusting zone 44. An oxygen supply gas 46 is coupled to the
regenerator 40 at an oxygen supply gas inlet 47. The oxygen supply
gas 46 is distributed in the coke combusting zone 44, such as with
a gas distribution system, and carries the fluidized spent catalyst
16 through the coke combusting zone 44. The coke is burned off the
spent catalyst 16 by contacting the spent catalyst 16 with the
oxygen supply gas 46 at regeneration conditions. In an exemplary
embodiment, air is used as the oxygen supply gas 46, because air is
readily available and provides sufficient O.sub.2 for combustion,
but other gases with a sufficient concentration of O.sub.2 could
also be used, such as purified O.sub.2. If air is used as the
oxygen supply gas 46, about 10 to about 15 kilograms (kg) of air is
required per kg of coke burned off of the spent catalyst 16.
Exemplary regeneration conditions include a temperature from about
500.degree. C. to about 900.degree. C. (900.degree. F. to
1,700.degree. F.) and a pressure of about 150 kPa to about 450 kPa
(20 PSIG to 70 PSIG). The superficial velocity of the oxygen supply
gas 46 is typically less than about 2 meters per second (6 feet per
second), and the density within the coke combusting zone 44 is
typically about 80 to about 400 kilograms per cubic meter (about
5-25 lbs. per cubic foot).
[0020] Coke is burnt off the spent catalyst 16 in the coke
combusting zone 44 to produce regenerated catalyst 18 that is
discharged into a regenerator separation area 48 by a combustor
riser disengaging device 50. Combustion gases, such as CO.sub.2,
CO, and H.sub.2O, are produced as the coke is burned off. The
combustion gases and other excess gases are vented from the
regenerator separation area 48 in a combustion gas vent line 56. A
regenerator cyclone 58 further separates regenerated catalyst 18
from the combustion gases before the combustion gases are vented.
After being separated from the combustion gases and other vented
gases, the regenerated catalyst 18 settles in a regenerator dense
bed 52 before transfer to the reactor 20 in a regenerated catalyst
transfer line 54. In some embodiments, the regenerator dense bed 52
provides a surge volume for variations in catalyst inventory within
the FCC unit 10.
[0021] Burning the coke off the spent catalyst 16 is an exothermic
reaction, and in many embodiments more heat is produced by burning
off the coke than is used to vaporize and crack the hydrocarbons in
the reactor riser 22. Lowering the temperature of the regenerated
catalyst 18 can improve the energy balance, and lower regenerated
catalyst temperatures produce a higher catalyst to hydrocarbon
ratio in the riser 22, which is typically desired. Therefore, the
regenerator may include one or more catalyst coolers 60 to cool the
regenerated catalyst 18 before transfer to the reactor 20. The
catalyst coolers 60 are positioned to cool the cracking catalyst 14
after it has been regenerated, because higher temperatures are
desired to burn off the coke and lower temperatures are desired for
the regenerated catalyst 18 transferred to the reactor 20.
[0022] In an exemplary embodiment, replacement gas 62 is used to
fluidize the regenerated catalyst 18 in the catalyst cooler 60,
where the replacement gas 62 is less than 1 mass percent gaseous
oxygen (O.sub.2). The replacement gas 62 is combined with air or
other gases containing O.sub.2 in some embodiments, so the O.sub.2
content of the fluidizing gas can be controlled and optimized. The
replacement gas 62 and the gas containing oxygen can be mixed or
used in ratios ranging from 1 to 100 percent replacement gas 62.
Suitable examples of replacement gas 62 include, but are not
limited to, steam, nitrogen, or combinations of the two. In
different embodiments, the replacement gas 62 is more than 95 mass
percent steam, or more than 95 mass percent nitrogen, or more than
95 mass percent of a steam and nitrogen mixture. Steam is condensed
in the fractionation zone 70 and discharged in the sour water
stream 76, and does not enter the gas concentration unit 78.
Therefore, the use of steam as the replacement gas 62 reduces the
total vapor burden on the gas concentration unit 78 as well as
reducing the quantity of oxygen-containing compounds, as described
more fully below. Nitrogen is an inert gas that does not reduce the
total burden on the gas concentration unit 78, but it does replace
oxygen-containing compounds such as O.sub.2, CO.sub.2, and CO.
Steam may contribute to hydrothermal deactivation of the cracking
catalyst 14 in some embodiments, in which case the amount of
nitrogen used for the replacement gas 62 is increased, up to about
100 percent in some embodiments. The replacement gas 62 is supplied
to the regenerator 40 by one or more fluidizing gas inlets 68
coupled to a replacement gas source 69 that supplies the
replacement gas 62. Air or other gases containing oxygen can be
mixed with the replacement gas 62 prior to the fluidizing gas
inlets 68 to control the oxygen content of the fluidizing gas in
some embodiments. Alternatively, a separate air fluidizing inlet
(not shown) can be used in conjunction with the fluidizing gas
inlet 68 for gases containing oxygen, if such gases are used. The
replacement gas source 69 can be a pressurized storage tank, a
plant-wide supply system, or other systems that provide a
sufficient supply of the replacement gas 62. The fluidizing gas
inlets 68 are configured to introduce the replacement gas 62 as the
fluidizing gas at a rate sufficient to fluidize the regenerated
catalyst 18 for the movement desired.
[0023] The regenerated catalyst 18 is fluidized in the catalyst
cooler 60 for catalyst movement. Different types of catalyst
coolers 60 are used alone or in combination in different
embodiments of the FCC unit 10, such as a back mix catalyst cooler
or a flow through catalyst cooler. A back mix catalyst cooler is a
pipe or tube that extends downward from the regenerator 40, and the
regenerated catalyst 18 moves in and out of the catalyst cooler 60
based on movement generated by the fluidizing gas. In a flow
through catalyst cooler, the catalyst enters one end of the
catalyst cooler 60, flows through the catalyst cooler 60, and exits
an opposite end of the catalyst cooler 60. Fluidizing gas is used
to move the catalyst through the different types of catalyst
coolers 60. The catalyst cooler 60 also uses a heat transfer fluid
64 that flows through the catalyst cooler 60, such as an oil or
water solution pumped through either a shell or tube of the
catalyst cooler 60, where the regenerated catalyst 18 passes
through the other of the shell or tube. Other types of catalyst
coolers 60 and heat transfer fluids 64 are used in different
embodiments. The heat transfer fluid 64 is then cooled and re-used,
discharged and replaced, or used for other heat transfer
purposes.
[0024] The regenerated catalyst 18 collects in the regenerator
dense bed 52, as described above, and a dense bed distributor 66
provides fluidizing gas for catalyst movement in and out of the
regenerator dense bed 52. In some embodiments, the replacement gas
62 is used as the fluidizing gas in the dense bed distributor 66.
The regenerated catalyst 18 flows from the regenerator dense bed 52
into the regenerated catalyst transfer line 54, which is also
fluidized with a gas for catalyst movement. In some embodiments,
the replacement gas 62 is used as the fluidizing gas in the
regenerated catalyst transfer line 54. In various embodiments, the
replacement gas 62 is used as the fluidizing gas for essentially
any catalyst movement in the regenerator that does not require
oxygen for combustion. Gases containing oxygen can be used in
conjunction with the replacement gas 62 throughout the FCC unit 10,
as described above, so the oxygen content of the fluidizing gas can
be controlled. Therefore, the replacement gas 62 can be the
fluidizing gas for any catalyst fluidization and movement in the
regenerator 40 except for within the coke combusting zone 44.
[0025] The combustion gases and excess O.sub.2 from the oxygen
supply gas 46 are captured and held in pores and interstitial
spaces in the regenerated catalyst 18, as well as being entrained
in the spaces between separate regenerated catalyst 18 pellets or
particles. These excess combustion gases and O.sub.2 are stripped
when the replacement gas 62 passes through the regenerated catalyst
18, because the replacement gas 62 replaces the oxygen-containing
compounds in and around the regenerated catalyst 18. The use of
replacement gas 62 not only prevents adding excess O.sub.2 to the
regenerated catalyst 18, but passing the replacement gas 62 through
the regenerated catalyst 18 also displaces and strips out excess
combustion gases and O.sub.2 to further reduce the quantity of
oxygen containing gases passing into the overhead stream 72. The
stripped combustion gases and excess O.sub.2 flow out of the
regenerator 40 in the combustion gas vent line 56, instead of the
regenerated catalyst transfer line 54. The use of replacement gas
62 for catalyst movement in the regenerator 40 does not eliminate
oxygen containing compounds from the gas concentration unit 78, but
can be used to lower the quantity of oxygen containing compounds
present.
[0026] While at least one exemplary embodiment has been presented
in the foregoing detailed description, it should be appreciated
that a vast number of variations exist. It should also be
appreciated that the exemplary embodiment or exemplary embodiments
are only examples, and are not intended to limit the scope,
applicability, or configuration of the application in any way.
Rather, the foregoing detailed description will provide those
skilled in the art with a convenient road map for implementing one
or more embodiments, it being understood that various changes may
be made in the function and arrangement of elements described in an
exemplary embodiment without departing from the scope, as set forth
in the appended claims.
* * * * *