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

Description

TECHNICAL FIELD

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

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.

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 (CO₂), and carbon monoxide (CO) increase corrosion on the gas concentration unit equipment. Excess oxygen, CO₂, and CO also increase the use of amines in the sulfur removal process, which increases costs.

Accordingly, it is desirable to develop methods and apparatuses for reducing excess oxygen, CO₂, 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

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.

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.

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

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

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.

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 CO₂ and CO, prior to transfer to the reactor.

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 (° 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.

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.

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.

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° C. to about 650° C. (750 degrees Fahrenheit (° F.) to 1,200° 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° C. to about 450° C. (300° F. to 850° F.).

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.

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° C. to about 140° C. (180° F. to 280° 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.

The overhead stream 72 includes non-condensable gases, such as oxygen (O₂), nitrogen (N₂), carbon dioxide (CO₂), 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° C. (95° 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.

Inert gases, such as N₂, increase the burden on the gas concentration unit 78 because of the increased volume of material processed. Carbon monoxide, CO₂ and O₂ 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 CO₂ 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 CO₂, CO, and O₂, 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.

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 O₂ for combustion, but other gases with a sufficient concentration of O₂ could also be used, such as purified O₂. 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° C. to about 900° C. (900° F. to 1,700° 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).

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 CO₂, CO, and H₂O, 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.

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.

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 (O₂). The replacement gas 62 is combined with air or other gases containing O₂ in some embodiments, so the O₂ 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 O₂, CO₂, 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.

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.

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.

The combustion gases and excess O₂ 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 O₂ 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 O₂ 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 O₂ to further reduce the quantity of oxygen containing gases passing into the overhead stream 72. The stripped combustion gases and excess O₂ 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.

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.

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.