WO2010144191A2

WO2010144191A2 - Fluid catalytic cracking process including flue gas conversion process

Info

Publication number: WO2010144191A2
Application number: PCT/US2010/033545
Authority: WO
Inventors: Frank J Elvin; Iraj Isaac Rahmim
Original assignee: Co2 Solutions Llc
Priority date: 2009-06-10
Filing date: 2010-05-04
Publication date: 2010-12-16
Also published as: US20100314290A1; WO2010144191A3

Abstract

A method is provided to reduce carbon dioxide emissions and increase the output of more valuable hydrocarbon products in a fluid catalytic cracking unit.

Description

Fluid Catalytic Cracking Process Including Flue Gas Conversion

Process

Background

The present invention relates to a fluid catalytic cracking process which takes advantage of a flue gas conversion plant including a Fischer-Tropsch process to reduce carbon dioxide emissions and increase the production of useful hydrocarbon products, such as diesel oil, jet fuel, and other products.

A fluid catalytic cracking unit typically includes a reactor, a catalyst regenerator, which burns off carbon from the catalyst used in the reactor, a flue gas treatment plant which treats the flue gas from the catalyst regenerator, and a fractionator, which separates the products from the reactor.

Summary The present invention discloses modifications to a fluid catalytic cracking unit in order to improve its hydrocarbon yield and to substantially reduce its carbon dioxide (CO2) emissions. As explained in more detail below, this is accomplished by combining one or more of the following modifications to the process: - Send the flue gases from the fluid catalyst cracking unit to a flue gas conversion plant which includes a Fischer-Tropsch process to convert H ₂ and CO into hydrocarbon products such as diesel fuel.

- Operate the catalyst regenerator for the catalyst cracking unit in partial burn to increase the production of CO and reduce the production of CO2. The increased CO production is advantageously used in the Fischer- Tropsch process to improve the hydrocarbon yield.

- Recycle the CO2 from the flue gas of the catalyst regenerator back into the catalyst bed of the regenerator to drive the net production of CO₂ to extinction so that no new CO₂ is produced, in order to substantially reduce the level of CO2 emissions from the fluid catalytic cracking unit and result in more CO production, which improves the yield of hydrocarbons in the Fischer- Tropsch process.

- Inject into the catalyst regenerator any low value refinery fuel or other hydrocarbon or carbon source product (in addition to the coke present in the catalyst to be regenerated) in order to increase the amount of carbon available for the production of CO (which is then utilized in the Fischer- Tropsch process to increase the hydrocarbon yield. Particularly useful for this purpose is the injection into the regenerator of the low value slurry oil from the bottoms of the main fractionator(s) of the fluid catalytic cracking unit. This also helps re-establish heat-balance in the reactor.

The heat balance is negatively affected with the combustion of carbon to CO (only 4,000 BTU/lb of carbon) instead of its combustion to CO₂ (14,000 BTU/lb of carbon) when operating in partial burn. - The incorporation of these process modifications to the fluid catalytic cracking unit may include the physical modification of the facility beyond the addition of the flue gas conversion plant with Fischer-Tropsch process. These modifications may include the addition of nozzles and distribution grids to the catalyst regenerator, the addition or modification of nozzles to the main fractionator(s), as well as resizing of components such as the regenerator and the gas plant, especially if the flue gas conversion plant does not include its own fractionators and instead makes use of the main fractionator(s) of the fluid catalytic cracking unit.

In one embodiment, the regenerator flue gas from the fluid catalytic cracking unit (which is primarily a mixture of CO, CO₂, and N₂₎ is sent to a flue gas conversion plant (which preferably is adjacent to the fluid catalytic cracking unit) that uses the Fischer-Tropsch process to react any CO in the flue gas with H₂ to make hydrocarbons such as diesel oil, jet fuel, gasoline, etc. (e.g., 33H₂ + 16CO = Ci₆H₃₄ + 16H₂O). The Fischer-Tropsch products may then be routed to the main fractionator of the fluid catalytic cracking unit or to a separate fractionator.

The hydrogen required for the Fischer-Tropsch reaction can be purchased (imported to the facility) or produced from natural gas or produced from the hydrocarbons in the off-gas from the fluid catalytic cracking unit in a hydrogen plant in the refinery (CH₄ + 2H₂O = 4H₂ + CO₂). The hydrogen can also be extracted from the off-gas from the fluid catalytic cracking unit. Alternatively, the required amount of hydrogen for the Fischer-Tropsch process could be produced if 67% of the total CO in the flue gas from the fluid catalytic cracking unit is routed to a CO shift reactor (or a Fischer-Tropsch reactor with shift catalyst). In this case no external H₂ is required. (H₂O + CO = CO₂ + H₂).

In some embodiments, slurry oil is injected into the regenerator, and the control system may be programmed to control the slurry oil injection at between 1 % and 10% of fluid catalytic cracking unit feed (preferably 5%).

CO₂ can be recycled with the air being injected into the catalyst regenerator of the fluid catalytic cracking unit to recycle the CO₂ to extinction and produce more CO. The control system may be programmed to measure and maintain the CO₂ recycle at the desired level between 10% and 300% of the air or oxygen rate (preferably 200%) to ensure the stoichiometric reaction 2C + O₂+ 2CO₂ = 2CO + 2CO₂ inside the catalyst regenerator. The controller maintains equilibrium while effectively recycling the CO ₂ to extinction. The effective overall equation becomes 2C + O₂ = 2CO. This further reduces CO ₂ emissions by eliminating the CO₂ produced from the regenerator. The overall reaction in the catalyst regenerator becomes 2C + O₂ = 2CO instead of C + O₂ = CO₂ or 4C + 3O₂ = 2CO + 2CO₂.

To heat-balance the fluid catalytic cracking unit when no CO is burned to CO_2, heat can be supplied from extra coke on the catalyst, derived from cracking heavier, higher carbon feeds, or by rerouting the fluid catalytic cracking unit fractionator bottoms (slurry oil) into the regenerator instead of routing it to heavy fuel oil storage. The slurry oil is about 90% carbon, making it an ideal source of carbon to produce CO in the regenerator and provide heat to heat-balance the fluid catalytic cracking unit. The CO is converted into hydrocarbon in the Fischer-Tropsch unit. The use of heavier feeds in the reactor and/or the recycle of slurry oil to the regenerator provide good ways to heat-balance the fluid catalytic cracking unit.

The reduction in available heat caused by not burning the CO to CO₂ in the regenerator also can be compensated by burning any other low value refinery fuel or product in the catalyst regenerator of the fluid catalytic cracking unit - such as absorber off-gas from the fluid catalytic cracking unit gas plant, and even gasoline from the fluid catalytic cracking unit if the price of gasoline is below diesel price, most of which will provide CO for diesel production in the Fischer-Tropsch process. In addition, any hydrocarbon or carbon source, for example charcoal or coal or wood or biomass, can be burned to produce the heat balance, and the CO from combustion can go to the Fischer-Tropsch process to produce hydrocarbons such as diesel fuel. Another source of heat for the reactor of the fluid catalytic cracking unit can be the excess heat from the Fischer-Tropsch process. For example, the heat from the Fischer-Tropsch process can be converted into electricity, which can be used to heat up the regenerator using microwaves or radiant heating coils. Also, electricity from any source could be used to balance the fluid catalytic cracking unit heat requirements.

Also, the heat from the Fischer-Tropsch process can be used to drive the compressor for the flue gas treatment for the fluid catalytic cracking unit, either by generating steam to directly drive the compressor or by generating steam to produce electricity to drive the compressor. As indicated above, one embodiment of the present invention injects slurry oil (or any other solid, liquid or gaseous source of carbon or hydrocarbon such as charcoal, coal, biomass, etc.) into the catalyst regenerator, converts it to CO in the regenerator, and converts this CO to hydrocarbon in the Fischer-Tropsch flue gas conversion plant. Residue cracking (catalytic cracking of heavy, high carbon feedstocks, vacuum bottoms, and atmospheric bottoms, as well as gas oil cracking) may be included in the process that is carried out in the fluid catalytic cracking unit. The fluid cracking catalyst preferably is a zeolite or non zeolite silica alumina catalyst. It preferably contains less than one part per million Pt or other oxidation promoters, oxidation catalysts or oxidation chemicals. It preferably has pore volumes of 0.3 to 0.8 cc/gram and a surface area of at least 50 m²/g. It preferably has at least 1 ppm Ni or similar reducing promoter and less than 5000 ppm of Ti.

The carbon on regenerated catalyst (CRC), regenerator temperature and the flue gas composition are preferably continuously monitored and the relative flows of combustion gas, slurry oil, and CO2 recycle streams adjusted to achieve maximum CO production at the lowest CO₂ recycle rate. The diesel oil and other hydrocarbon products from the Fischer-Tropsch flue gas conversion plant may be processed in the fluid catalytic cracking unit main fractionator.

Brief Description of the Drawings:

Figure 1 is a schematic of a standard prior art fluid catalytic cracking unit (FCCU);

Figure 2 is a schematic of a fluid catalytic cracking unit including one embodiment of the present invention;

Figure 3 is a schematic showing the inputs and outputs for the Flue gas conversion unit, which is Section 6 in Figure 2;

Figure 4 is a schematic showing an alternative embodiment of the Flue gas conversion unit of Figure 3; Figure 5 is a schematic showing a second alternative embodiment of the Flue gas conversion unit of Figure 3;

Figure 6 is a schematic showing another alternative embodiment of the Flue gas conversion unit;

Figure 7 is a schematic showing some of the modifications which may be made to the catalyst regenerator;

Figure 8A is an enlarged view of the slurry oil injection nozzle of Figure 7;

Figure 8B is an end view of the nozzle of Figure 8A;

Figure 9 is a table showing the fuel oil yield for the base case of a prior art fluid catalytic cracking unit;

Figure 10 is a table showing the fuel oil yield for a fluid catalytic cracking unit with two different embodiments of the present invention wherein the regenerator is operated in partial CO burn. In case 2a the CO2 is not recycled, while in case 2B the CO₂ is recycled to extinction (in both cases there is no slurry oil injected into the regenerator);

Figure 11 is a table showing the fuel oil yield for a fluid catalytic cracking unit with the same two embodiments of the present invention as in Figure 10, except slurry oil is injected into the regenerator in both of these cases; Figure 12 is a table showing the fuel oil yield for a fluid catalytic cracking unit with the same two embodiments of the present invention as in Figure 10, except that a shift reactor is used to produce H_2, in one instance there is no CO₂ recycle while in the second case there is CO₂ recycle to extinction; and Figure 13 is a table showing the fuel oil yield for a fluid catalytic cracking unit with the same two embodiments of the present invention as in Figure 10, except with a different fresh feedstock.

Detailed Description:

Description of the Prior Art Fluid Catalytic Cracking Process shown in

Figure 1

A typical prior art fluid catalytic cracking unit 10' has five major sections as shown in Figure 1 :

- section 1 is the fluid bed reactor 12'

- section 2 is the main fractionator(s) 14'

- section 3 is the gas plant 16'

- section 4 is the catalyst regenerator 18'; and - section 5 is the flue gas treatment plant 20'.

The yields from this fluid catalytic cracking unit 10' are shown in Figure 9. These are actual yields. (The yields in the other tables are calculated, not actual.)

Fluid cracking catalyst (FCC) in the fluid bed reactor 12' (Section 1 ) facilitates a reaction which converts the heavy hydrocarbon feed 22 (long- chain hydrocarbon molecules) into high value transportation fuels 24, 26 and liquid petroleum gases (LPG) 28, 30. The feed 22 is atomized with steam 34 on its way into the reactor. In the reactor 12', the atomized heavy hydrocarbon feed 22 is mixed with very hot, powdered catalyst, causing the heavy hydrocarbon feed 22 to vaporize and crack into smaller molecules. The cracked product vapors are then separated from the spent catalyst. The spent catalyst is stripped with steam 36 in the reactor stripper 48' to remove entrained hydrocarbons and is sent to the regenerator 18', and the cracked hydrocarbon vapors are sent to the main fractionator(s) 14'. Some of the feed 22 either is not converted or is only partially converted, resulting in low value slurry oil 32, which comes out of the bottoms of the fractionator(s) 14'). Some of the feed 22 is converted to low value coke, which is deposited on the spent catalyst.

The reactor 12' operates between 85O⁰F and 1100⁰F, at pressures of between 2 psig and 60 psig and with catalyst to oil ratios of between 2:1 and 30:1. The main fractionator 14' (Section 2) separates the diesel 26 and slurry oil 32 from the gas 38, LPG 28, 20 and gasoline 24 by distillation.

The feed atomizing steam 34 and catalyst stripping steam 36 are removed from the fractionator 14' overhead receiver as condensed water 40. The gas plant 16' (Section 3) further separates the off-gas 38, LPG 28, 30 and gasoline 24 by distillation and absorption.

In the catalyst regenerator 18' (Section 4), the coke is burned off the spent catalyst with a gas containing oxygen, usually air 42. The flue gases 44 from the catalyst regenerator 18' (Section 4) are a mixture of CO, CO2, SO2, N₂, NO_x and catalyst fines. The catalyst regenerator 18' operates at temperatures between 1100⁰F and 1600⁰F and similar pressures to the reactor 12'. In the flue gas treatment section 20' (Section 5), CO in the flue gas 44, if present, is converted to CO₂ in a waste heat boiler, and the SO2 and catalyst fines are removed in a wet gas scrubber. The CO2 and N₂ exit the fuel gas treatment section 20' (Section 5) at the outlet 46.

Fluid cracking catalyst (FCC) circulates continuously from the reactor 12' (Section 1 ) to the catalyst regenerator 18' (Section 4), flowing from the regenerator 18' to the reactor 12' along the path (X), and from the reactor 12' to the regenerator 18' along the path (Y). The catalyst provides four important functions: cracking; coke removal; removal of heat from the regenerator 18' (Section 4); and supply of heat to the reactor 12' (Section 1 ).

The fluid catalytic cracking unit Reactor (Section 1): Hot catalyst from the catalyst regenerator 18' (Section 4), at the regenerator temperature (approximately 1400⁰F) flows into the reactor 12' (Section 1 ) along the path labeled (X). The hot catalyst provides the endothermic heat of reaction, heat of vaporization, and the heat to heat the oil to its cracking temperature. The catalyst circulation rate depends on the feed preheat temperature, regenerator temperature, and reactor temperature, and is usually a ratio of about 6:1 catalyst to oil. However, some designs operate as high as a 30:1 catalyst to oil ratio. The reactor temperature is controlled at approximately 1000⁰F.

The feed 22 to the reactor 12' (Section 1 ) is atomized with steam 34. The reactor 12' converts a heavy hydrocarbon feedstock 22, with an API gravity of between 10° and 35° and a Conradson Carbon content of between 0% and 10%, into C₅+ gasoline 24, diesel 26, slurry oil 32, absorber off-gas 38 (which may include H₂, H₂S, Ci s, C₂S,), C₃S LPG 28, C₄ S LPG 30, and coke. Most of the coke is produced in the cracking reaction where it is deposited onto the surface of the catalyst. The coke contains traces of sulfur, and some coke results from a small quantity of hydrocarbons that are entrained and absorbed onto the catalyst as it leaves the reactor-stripper 48' and enters the regenerator 18'. The vapor products may be separated from the spent catalyst in the reactor 12' by many known separation devices such as cyclones. This ensures the correct oil/catalyst residence time and ensures that no catalyst goes over into the main fractionators 14' (Section 2).

The catalyst is stripped with steam 36 in the reactor stripper 48' as it flows from the reactor 12' (Section 1 ) to the regenerator 18' (Section 4), and the stripped hydrocarbons and steam are returned to the reactor 12'.

The atomizing steam 34, stripping steam 36, and reactor products leave the reactor 12' as a vapor and flow into the fractionators 14' (Section 2) for separation.

The fluid catalytic cracking unit Regenerator (section 4):

The catalyst flows from the reactor 12' (Section 1 ) to the regenerator 18' (Section 4) where the coke is burned off and the catalyst is reheated. A fluid catalytic cracking unit 10' that is processing a gas oil with low Conradson carbon (<.05%) may only produce 5% coke. However, a fluid catalytic cracking unit 10' processing a residue feedstock with up to 10% Conradson carbon may produce up to 12% coke. The coke includes about 6% hydrogen, 94% carbon, and trace amounts of sulfur. It is burned off the catalyst with an oxygen bearing gas 42, such as air. The regenerator temperature is approximately 1400⁰F, and in some residue feedstock processing units the temperature is controlled with steam coils and heat exchangers to remove any excess heat.

Flue Gas Treatment (Section 5) The flue gases 44 (which may include H₂O, SO₂, N₂, CO and CO₂.) flow from the regenerator 18' (Section 4) to the flue gas treatment plant 20' (section 5) where any CO is burned to CO_2, and the SO ₂ and catalyst fines are removed. The flue gases 44 before treating can have a varied composition. They may contain 0% to 50% CO; 25% to 100% CO₂, 0% to 6% O2; and 0%-80% N₂ depending on how the fluid catalytic cracking unit is operated, and whether air, or oxygen, or oxygen in air, or O₂ with other gases are used for combustion in the regenerator 18'. The flue gas treatment plant 20' may include a waste heat boiler which converts CO to CO2 and may have a NO_x treatment reactor.

The fluid catalyst

The fluid catalyst provides the surface area, catalytic acidity and activity in the reactor 12'. As it leaves the reactor 12', it removes the unwanted coke (a compound with about 6% hydrogen and 94% carbon) produced during the cracking reactions. In the catalyst regenerator 18' (Section 4) the catalyst absorbs most of the heat released when the coke is burned off the catalyst with an oxygen rich gas 42 (usually air). The catalyst is usually made from alumina-silica micro-spheres with diameters of 2-200 microns and impregnated with zeolites (including HY, REY, USY, ZSM-5), additives, including bottom cracking additive (BCA) max diesel additive, metal traps, and oxidation additives and co-catalysts such as Pt.

Modified Plant Including Flue Gas Conversion Using Fisher-Tropsch Process

Figure 2 shows the fluid catalyst cracking unit 10 that has been modified to incorporate a flue gas conversion plant 50 (Section 6) within the facility.

The flue gas conversion Plant (Section 6):

The flue gas conversion plant 50 (Section 6) has within it a number of individual process units, including a Fischer-Tropsch process Plant (also referred to as an F-T plant), which produces useful hydrocarbons from the CO in the flue gas of the regenerator 18. There are, depending on the specifics of the usage, a number of arrangements that may be used. For example, the Fischer-Tropsch reactor itself can be slurry-type or tubular fixed-bed or fluidized bed. The Fischer-Tropsch catalyst might be cobalt-based or iron- based or some other, newer, alternative. In general, the flue gas conversion plant 50 may include the following elements (See Figure 6):

• Shift reactor in order to fix the ratio of H₂/CO to slightly above 2.

• The Fischer-Tropsch reactor(s). Depending on the size and design of the facility, this might be one or more reactors. Significant amounts of medium pressure steam (approx. up to 200° C) are generated in these reactors. This steam can be used in heating other process streams and units, as necessary, and can be used to generate electricity for internal use or export. • Separation equipment for the removal of CO₂ as well as any remaining

H₂/CO, and separation of light hydrocarbon gases from naphtha, diesel/jet, and lubes/waxes.

• Reactors and associated facilities for hydrotreating naphtha and diesel/jet fuel and hydrocracking lubes and waxes to lighter hydrocarbons.

• Separation equipment for the separation of the various hydrocarbons from one another. (In this case, this might be replaced with the fluid catalytic cracking unit main fractionators 14.)

The schematic of Figure 2 involves several modifications to the standard, prior art fluid catalytic cracking unit 10' of Figure 1 , which may include the modification of the fluid catalytic cracking unit main fractionator 14', regenerator 18', and gas plant 16', as explained in more detail below. It also includes the addition of a flue gas conversion plant 50 (Section 6). The flue gas conversion plant 50 may have a CO shift reactor (See Figure 5), or there may not be a CO shift reactor (See Figure 3). It may include a hydrogen plant (See Figure 4), or it may use imported hydrogen.

The fluid catalyst cracking unit 10 includes the full integration of the Flue gas conversion plant 50 (and associated equipment such as mild hydrocracker and additional hydrotreating facilities, shift reactor and hydrogen plant) with the fluid catalytic cracking unit regenerator 18, fractionator 14 and gas plant 16. Depending on the output from the Fischer-Tropsch flue gas conversion plant 50, modifications to the main fractionator 14' and the gas plant 16' may not be necessary. For instance, if the Fischer-Tropsch flue gas conversion plant 50 includes its own fractionator(s), then modifications to the main fractionator 14' and the gas plant 16' may not be made.

New Equipment

In order to modify the fluid catalyst cracking unit 10' shown in Figure 1 to make the fluid catalyst cracking unit 10 shown in Figure 2, a new fluid catalytic cracking unit flue gas conversion plant 50 (Section 6) is added to the fluid catalytic cracking unit. The main process unit in the flue gas conversion section 50 is a Fischer-Tropsch (FT) plant.

Figure 3 shows an example of a flue gas conversion plant 50 (Section 6 of Figure 2), without shift reactor, wherein H₂ is imported from outside the fluid catalytic cracking unit complex. In that case, only the Fischer-Tropsch process is needed to convert the CO to hydrocarbons such as diesel oil in the flue gas conversion plant 50 (Section 6).

Figure 4 shows an example of a flue gas conversion plant 50 (Section 6 of Figure 2), wherein H₂ is generated in a hydrogen plant that is incorporated into the fluid catalytic cracking unit complex, using either natural gas or absorber off-gas 38 from the fluid catalytic cracking unit gas plant. Figure 5 shows an example of a flue gas conversion plant 50 (Section

6 of Figure 2), in which sufficient H₂ for the Fischer-Tropsch plant can be made on site in a shift reactor or modified Fischer-Tropsch Water is added to the shift reactor to facilitate the shift reaction. This amount of water will react exactly with the remaining flue gas CO in the Fischer-Tropsch plant to make hydrocarbons, including diesel fuel.

In converting a prior art plant 10' to the plant 10 shown in Figure 2 (assuming the flue gas conversion plant 50 does not have its own fractionator), a new nozzle may be added either in the reactor vapor overhead line 52 or into the main fractionation tower itself 54. This allows the product from the flue gas conversion plant 50 (Section 6) to be introduced and processed in the fractionators 14 (Section 2).

The catalyst regenerator 18 also may be modified to improve the conversion of CO₂ to CO as shown in Figures 2 and 7, adding a spray nozzle and/or an additional combustion air grid. The slurry oil 32 from the main fractionators is injected into the lower section of the regenerator 18 (Section 4) preferably about three feet above the combustion air grid 56, at a point in the regenerator where the carbon on the catalyst is lowest and the O₂ concentration is the highest. A secondary oxygen source 42* is injected along with the slurry oil 32 to provide atomization and controlled stoichiometric combustion of the slurry oil 32 to CO and H₂O. Part of the recycled CO₂ also can be injected along with the slurry oil 32 to facilitate a direct C + CO₂ = 2CO reaction. The CO₂ recycle also can be injected through the combustion air grid 56 along with the oxygen rich combustion gas 42. The addition of a nozzle 58 (See Figures 7, 8A, and 8B) or nozzles 58 and a distribution grid 60 inside the regenerator, preferably between 2 feet and 20 feet, and more preferably approximately 6 feet, above the primary combustion air grid 56, allows the recycle of CO₂ into the high carbon zone of the regenerator 18 away from the oxygen rich combustion air inlet 42 to maximize the reaction C + CO₂ = 2CO.

Nozzles 58, described in more detail below, may be added to allow the injection of any hydrocarbon, crude oil, oil sand, tar sand, synthetic oil from coal, tar sands or oil sands, or bio-mass, natural gas, absorber fluid catalytic cracking unit gas plant off-gas 38 or fluid catalytic cracking unit fractionator bottoms (also referred to as slurry oil 32), without contacting water or water vapor, for the purpose of heat balancing the fluid catalytic cracking unit 10 when recycling CO₂.

In a two stage regenerator or a regenerator with two separate vessels, the slurry oil 32 can be injected into both catalyst beds but preferentially is injected into the low CRC area in the full CO burn vessel. Similarly the CO₂ can be injected into both vessels, but preferentially into the high CRC area in the partial burn vessel.

As can be appreciated from Figure 7, the CO₂ recycle can be injected into the regenerator 18 through the combustion air grid 56 with the air or oxygen rich combustion gas, with the slurry oil 32 via the nozzle 58, with the secondary oxygen source 42* at the nozzle 58, and/or through its own CO₂ recycle grid 60. Referring briefly to Figures 7, 8A, and 8B, the nozzle 58 includes a slurry oil delivery pipe 62 inside a slightly larger "sleeve" pipe 64 in an arrangement similar to that of a single tube, shell and tube heat exchanger. The slurry oil travels in the "tube side" 62, while air or recycled CO242^* (or a mixture of these) travels along the "shell side" 64. This sleeve arrangement provides an insulating effect on the pipe 62 to keep it relatively cool against the heat of the regenerator 18, to prevent unwanted coking of the slurry oil in the pipe 62.

The pipe 62 terminates inside the sleeve 64 at a perforated plate 66 which allows the air/recycled CO₂ 42^* to flow around and along the pipe 62 to continually cool it, and then diffuse into the slurry oil 32 in an atomizing chamber 68. Finally, the mixture of the slurry oil 32 and the air/recycled CO₂ 42^* are sprayed out into the regenerator 18 through a horizontally oriented slotted opening 70 to ensure that the slurry oil is sprayed substantially horizontally, away from the refractory-lined walls of the regenerator 18 and not directed toward the distributor grids 60, 56.

The nozzle 58 includes a flange 72 for mounting to the regenerator wall. The nozzle 58 projects into the regenerator at least far enough to ensure that it clears the refractory material lining the wall of the regenerator 18.

New fluid catalytic cracking unit Operation The fluid catalytic cracking unit 10 operates in partial CO burn. This means that the CRC is controlled between 0.1 % and 1.2 % in the fluid catalytic cracking unit regenerator 18 (Several methods are known in the industry for determining and controlling the CRC in the regenerator. For instance, the catalyst may be sampled hourly and the level of CRC can then be visually established, or the temperature in the regenerator can be monitored to empirically determine and control the CRC level). The treated flue gases 46 from the flue gas treatment 20 (Section 5) are routed to the new flue gas conversion plant 50 (Section 6) where the CO is converted to diesel fuel. The process is enhanced if the excess CO₂ from the flue gas conversion plant 50 (section 6) is recycled to the catalyst bed of the fluid catalytic cracking unit regenerator 18 to boost CO production, and ultimately convert all coke to CO instead of CO₂. The CO₂ recycle, CRC, and combustion air flow are carefully controlled to establish the following reaction 2C + O₂+ 2CO₂ = 2CO + 2CO₂. By carefully controlling operating variables, the net reaction is 2C + O2 = 2CO, and results in all of the carbon being converted into CO with no net production of CO2. The CO and CO2 are in equilibrium at a ratio of about 1 :1. This ratio stays constant as the CO₂ is recycled, as it is defined by thermodynamic conditions. Therefore, as the CO 2 is recycled, more Carbon is converted to CO. Ultimately, there is no net CO2, only CO2 recycle. All the carbon on the catalyst is converted to CO.

The heat released in the regenerator 18 in this operation is less than that typically required to balance the requirements of the fluid catalytic cracking unit reactor 12 (an exception may occur when processing high residue feedstocks, particularly if oxygen is injected into the regenerator to burn off the coke, as explained in more detail later). Therefore, additional fuel is injected into the catalyst regenerator 18. This can come from any carbon or hydrocarbon source (in addition to the coke present in the catalyst to be regenerated), and will also be converted to CO (and eventually into diesel fuel in the flue gas conversion plant 50). A readily available source of additional fuel is the slurry oil 32 from the bottoms of the main fractionators, as it has a low value and a high carbon content, although absorber off-gas 38 from the fluid catalytic cracking unit gas plant could be used instead or in addition to the slurry oil to add heat or an entirely different source of carbon could be used. Heat balances are shown in Figure 12.

The flue gas conversion plant 50, Figure 2 Section 6, Figure 3, and Figure 4

The flue gas conversion plant 50 (Section 6) converts the CO from the flue gas of the catalyst regenerator 18, water, and external H₂ if needed by the Fischer-Tropsch (FT) plant to hydrocarbons. In the example of yields shown in Figure 12, the hydrocarbon product from the Fischer-Tropsch process is middle distillate or diesel fuel, which is then processed in the main fractionator 14 of the fluid catalytic cracking unit. The CO for the Fischer- Tropsch process comes from the flue gas of the catalyst regenerator 18. The hydrogen may come from a variety of sources. For example, it can be imported as shown in Figure 3. Alternatively, H₂ may be produced by an electrolytic process. Hydrogen also can be extracted from the fluid catalytic cracking unit absorber off-gas 38 by membrane separation or pressure swing absorption. This configuration also is shown in Figure 3. Alternatively, as shown in Figure 4, the H₂ can be generated from an onsite H₂ plant using natural gas or preferably fluid catalytic cracking unit off- gas 38 as a feed. (The H₂ also could be supplemented from an external source and/or from H₂ in the fluid catalytic cracking unit absorber off-gas 38.) Alternatively, as shown in Figure 5, the H₂ can also be produced in a shift reaction within the Fischer-Tropsch plant or in a separate shift unit ahead of the Fischer-Tropsch plant. In that case, the H₂ plant reaction is CH₄ + 2H₂O = 4H₂ + CO₂. (The H₂ also could be supplemented from an external source and/or from H₂ in the fluid catalytic cracking unit absorber off-gas 38). Other methods for the manufacture of H₂ include, but are not limited to, partial oxidation of hydrocarbons (e.g., 2CH₄ + O₂ = 2CO + 4H₂).

The CO₂ from either the hydrogen plant (Figure 4) or the shift reactor (Figure 5) is vented to atmosphere or, alternatively, can be recycled to the catalyst regenerator 18. The shift reaction is H₂O + CO = CO₂ + H₂. The shift reactor consumes 67% of the CO from the treated flue gases 46 but still results in significant diesel fuel production in the Fischer-Tropsch plant. Heat (See dotted line in Figure 2) from the flue gas conversion plant 50 (Section 6) is recycled from the flue gas conversion plant 50 in the form of hot CO₂ that is recycled to the catalyst regenerator 18 to heat-balance the catalyst regenerator 18 (Section 4).

The calculated yields from the modified fluid catalytic cracking unit with the Fischer-Tropsch flue gas conversion plant 50 (Section 6) are shown in Figures 10 and 11. The improved process results in increased diesel fuel yields, reduced slurry oil yields, and lower CO ₂ emissions. Figure 9 shows the base gas oil yields from the base fluid catalytic cracking unit 10' without the Fischer-Tropsch flue gas conversion. In this case, it can be seen that a feed of 36,930 barrels per day yields 6,377 barrels per day of diesel fuel. This partial CO burn operation is in heat balance. Figure 10 shows the yields in two different cases in which the fluid catalytic cracking unit 10 is coupled with the Fischer-Tropsch flue gas conversion plant 50 without shift in accordance with Figures 2 and 4, with the flue gases 46 being fed to the flue gas conversion plant 50 (Section 6) but without the slurry oil 32 being injected into the regenerator 18 (Section 4). Column 2a is for the case in which the CO2is not recycled, and column 2b is for the case in which the CO2 is recycled to extinction.

There is a substantial improvement in yield over the base case of Figure 9, especially when the CO2 is recycled to extinction and 100% of the regenerator CO2 emissions are eliminated. Without recycling the CO2 to extinction, the same feed yields 7,078 barrels per day of diesel fuel, and with recycling the CO₂ to extinction, it yields 7,773 barrels per day of diesel fuel as compared with 6,377 barrels per day in the base unit. No external heat is required to heat balance the coupled partial burn case 2a. However, the recycled CO₂ case requires 98 million BTU/hr to heat balance. This heat (see dotted line in Figure 2) can be provided by the flue gas conversion plant 50 (Section 6) or, alternatively, from other sources.

Figure 11 shows yields for the same process as shown in Figure 10, except with the slurry oil 32 being injected into the regenerator 18 (Section 4). In this case, the CO comes from the flue gases 46, from the carbon deposited on the catalyst in the fluid catalytic cracking unit reactor 12 (Section 1 ), and from the carbon in the slurry oil 32 injected into the regenerator 18 (Section 4). The heat from burning the slurry oil 32 in the regenerator 18 once again heat-balances the operation. In this case, the same feed produces 8,637 barrels per day of diesel fuel without CO₂ recycle and 9,332 barrels per day of diesel fuel with CO₂ recycle, as compared with 6,377 barrels per day in the base case.

Figure 12 shows the case in which the shift reaction is used as shown in Figure 5, and the flue gases 46 go to the flue gas conversion plant 50 (Section 6), but the slurry oil 32 does not go to the regenerator 18 (Section 4). In this case, part of the CO is converted to H₂ in the shift reactor. Carbon on the catalyst from the residue feedstock supplies the heat to once again heat- balance the operation. In this case, the same feed produces 6,638 barrels per day of diesel fuel without CO₂ recycle and 6,898 barrels per day of diesel fuel with CO₂ recycle.

Figure 13 shows a different fresh feed, using the arrangement of Figures 2 and 4, with the slurry oil 32 not being fed to the regenerator 18 (Section 4) and with the flue gases 46 being fed to the flue gas conversion plant 50 (Section 6), both with and without CO₂ recycle. It is interesting to note that the application of the processes disclosed in this specification also allows for the operation of fluid catalytic cracking units under some unique and particularly interesting conditions. Already discussed above are the capabilities to operate: - under partial burn in the regenerator 18 to increase the production of

CO, which is advantageously used in the Fischer-Tropsch process to improve the yield of fuel oils from the fluid catalytic cracking unit 10.

- under CO2 recycle to drive net production of CO2 to extinction. This results in a substantial reduction, if not a complete elimination, of CO2 emissions from the fluid catalytic cracking unit 10.

- under CO₂ recycle to increase production of CO in the regenerator 18, which is advantageously used in the Fischer-Tropsch process to improve the yield of fuel oils from the fluid catalytic cracking unit 10.

- with injection of low value refinery fuel or other hydrocarbon or carbon source product in addition to the coke present in the catalyst to be regenerated (preferably low value slurry oil from the bottoms of the main fractionator) in order to increase the amount of carbon available for the production of CO (which is then utilized in the Fischer-Tropsch process to increase the yield of fuel oils in the fluid catalytic cracking unit). - with utilization of absorber Off-Gas from the gas plant 16 to obtain hydrogen for use in the Fischer-Tropsch process.

Also, air can be injected into the regenerator 18 to help burn the coke. A better choice is to inject oxygen into the regenerator 18, but if the coke is being burned to CO2, the amount of heat generated in the regenerator 18, when injecting oxygen, may be too great. This is especially true when operating with high residue feedstocks (such as feedstock with up to 10% Conradson carbon which may produce up to 12% coke). The amount of heat generated can be so high that it risks melting the regenerator 18, even when using steam coils to remove the excess heat. Even when high residue feedstocks are not involved, it may be necessary to dilute the air or oxygen with nitrogen to prevent this high heat load in the regenerator 18.

However, if the CO₂ is recycled so that there is no net production of CO2, then all the coke is burned to CO which has a considerably lower heat output (the thermodynamic equilibrium is normally a 1 :1 ratio of CO:CO2. If the CO2 is recycled, then the coke in the catalyst in the regenerator 18 will burn to CO in order to maintain that thermodynamic equilibrium). This substantially reduces the heat load as the heat released when burning the carbon to CO is one third of the heat released when burning the carbon to CO₂.

The fluid catalytic cracking unit can then operate using these high residue feedstocks with oxygen injection diluted with the CO₂ recycle, eliminating the need to dilute the oxygen with nitrogen. The reason is two- fold:

1 - The heat load is considerably lower when burning the carbon to CO instead of when burning it CO2.

2- The CO2 recycle dilutes the oxygen without the need for nitrogen. This provides a distinct advantage in that there is no longer a need to contend with nitrogen coming off as part of the flue gases of the regenerator 18. The separation is much simpler if there are only CO and CO2 coming off of the regenerator 18 (because the recycled CO2 is acting as the diluent for the oxygen) instead of CO, CO2, and nitrogen (with the nitrogen acting as the diluent). If the nitrogen is not separated out of the flue gas stream before it is sent to the flue gas conversion plant 50, then this large volume of nitrogen must be pressurized from the operating pressure in the regenerator (up to 60 PSIG) to that of the Fischer-Tropsch process (about 300 PSIG), and this could be very expensive.

It will be obvious to those skilled in the art that modifications may be made to the embodiments described above without departing from the scope of the present invention.

Claims

What is claimed is:

1. A fluid catalytic cracking process, comprising the steps of: feeding a high molecular weight hydrocarbon feedstock into a reactor; mixing the feedstock with catalyst and cracking and vaporizing the feedstock within the reactor; recycling spent catalyst from the reactor to a regenerator; burning off coke from the spent catalyst within the regenerator to regenerate the spent catalyst, producing flue gases including CO and CO₂, which leave the regenerator through a flue; returning the regenerated catalyst back to the reactor; feeding at least some of the flue gases from the regenerator to a flue gas conversion plant; reacting CO in the flue gases with hydrogen and producing hydrocarbon products using a Fischer-Tropsch process in said flue gas conversion plant; and recycling CO₂ from the flue gases back to the regenerator.

2. A fluid catalytic cracking process as recited in claim 1 , wherein coke on the spent catalyst is a first carbon source product fed into the regenerator and further comprising the step of injecting an additional carbon source product into the regenerator.

3. A fluid catalytic cracking process as recited in claim 2, and further comprising the steps of : sending the product from the reactor to a main fractionator; separating the product in the fractionator by means of distillation; and sending some of the fraction produced by the fractionator to the regenerator to serve as at least some of said additional carbon source injected into the regenerator.

4. A fluid catalytic cracking process as recited in claim 3, and further comprising the steps of: sending at least a portion of the off-gas from said main fractionator to the flue gas conversion plant and using that portion of the off-gas as a source of hydrogen for the Fischer-Tropsch process.

5. A fluid catalytic cracking process as recited in claim 4, and further comprising the step of sending said hydrocarbon products produced by the Fischer-Tropsch process to the main fractionator of the fluid catalytic cracking unit.

6. A fluid catalytic cracking process as recited in claim 1 , including the step of recycling said CO₂ to drive the net production of CO₂ in the regenerator to extinction.

7. A fluid catalytic cracking process as recited in claim 1 , wherein said hydrogen is imported into the fluid catalytic cracking unit.

8. A fluid catalytic cracking process as recited in claim 1 , wherein said hydrogen is generated electrolytically.

9. A fluid catalytic cracking process as recited in claim 3, and further comprising the step of using natural gas to generate hydrogen for the Fischer- Tropsch process.

10. A fluid catalytic cracking process as recited in claim 4, wherein some of said additional carbon source injected into the regenerator is the bottoms from the fractionator.

11. A fluid catalytic cracking process as recited in claim 1 , including the step of recycling enough CO₂ from the flue gases back to the regenerator to drive the net production of CO₂ in the regenerator to extinction.

12. A fluid catalytic cracking process as recited in claim 11 , wherein said feedstock is a high residue feedstock containing up to 10 % Conradson carbon, and further comprising the steps of: injecting oxygen into the regenerator; and diluting said oxygen with the recycled CO2 from the flue gases.

13. A fluid catalytic cracking process as recited in claim 1 , wherein said Fischer-Tropsch process produces waste heat; and further comprising the step of using at least some of the waste heat produced by the Fischer- Tropsch process to drive a compressor in the flue gas conversion plant.

14. A fluid catalytic cracking process as recited in claim 13, including the step of using said waste heat to produce steam and using the steam to drive the compressor.

15. A fluid catalytic cracking process as recited in claim 13, including the step of using said waste heat to generate electricity and using electricity generated from the waste heat to drive the compressor.

16. A fluid catalytic cracking process, comprising the steps of: feeding a high molecular weight hydrocarbon feedstock into a reactor; mixing the feedstock with catalyst and cracking and vaporizing the feedstock within the reactor; recycling spent catalyst from the reactor to a regenerator; burning off coke from the spent catalyst within the regenerator to regenerate the spent catalyst, producing flue gases including CO and CO2, which leave the regenerator through a flue; returning the regenerated catalyst back to the reactor; feeding at least some of the flue gases from the regenerator to a flue gas conversion plant; reacting CO in the flue gases with hydrogen and producing hydrocarbon products using a Fischer-Tropsch process in said flue gas conversion plant, wherein said Fischer-Tropsch process produces waste heat; and using at least some of the waste heat produced by the Fischer-Tropsch process to drive a compressor in the flue gas conversion plant.

17. A fluid catalytic cracking process as recited in claim 16, including the step of using said waste heat to produce steam and using the steam to drive the compressor.

18. A fluid catalytic cracking process as recited in claim 17, including the step of using said waste heat to generate electricity and using electricity generated from the waste heat to drive the compressor.