EP0247836A1 - Removing sulfur oxides from flue gases of FCC units - Google Patents

Abstract

An improved process for reducing SOx in the flue gas from FCC regenerators operated in complete combustion mode is disclosed. The FCC riser is modified to include an SOx desorption zone (D) upstream from the zone in the riser in which regenerated cracking catalyst (A) contacts hydrocarbon feedstock (E). The circulating catalyst inventory (A) includes a regenerable SOx adsorbent. In the SOx desorption zone (D), the hot circulating catalyst inventory (A) is mixed with a reducing gas (B) and water vapor (C) and the gas/solid mixture is maintained in that zone for sufficient time to desorb.

Description

• This invention relates to an improved process for removing sulfur oxides (SOx) from the flue gas of FCC regenerators using an SOx transfer agent to absorb the SOx in the regenerator and desorb the sulfur in the riser in the form of a sulfur-containing gas.
• A necessary and integral part of a fluid catalytic cracking reactor involves the regenerator wherein the spent catalyst has its activity restored. Regeneration of spent catalyst is generally effected after separation of the spent catalyst from the reaction products. The spent catalyst is removed from the reaction zone and contacted in a stripping zone with a stripping medium, usually steam to remove vaporized and entrained and/or occluded hydrocarbons from the catalyst. From the stripping zone, a stripped catalyst is passed into a regeneration zone wherein the stripped spent catalyst is regenerated by burning coke deposits therefrom with an oxygen-containing gas, usually air. The resulting hot regenerated catalyst from the regeneration zone is then recycled to the reaction zone in contact with additional hydrocarbon feed. When the hydrocarbon feed to the fluid catalytic cracking reactor riser contains sulfur, oxides of sulfur report in the flue gas from the regenerator, creating a noxious gas stream unless the feed is low in sulfur. A similar problem of sulfur oxide emissions resulting from regeneration of spent solid contact material by burning occurs in the operation of fluid cokers or selective vaporization processes of the type described in U. S. 4,263,128 (Bartholic), to which attention is directed for detail. Sulfur oxide emissions in flue gases also occur in operation of coal fired boilers or any process in which sulfur-containing fuel is combusted.
• Flue gas sulfur removal units have been expensive to build and are often plagued with operating and/or by-product disposal problems. Flue gas sulfur removal units fall into three general categories; wet systems, once through dry systems, and regenerable systems.
• Wet flue gas sulfur removal systems consume large quantities of water, require stack gas reheat, create slurries that are dewatered in crystallizers or settling ponds, and are built employing expensive metallurgy to combat corrosion. Once-through dry systems generate large quantities of solids that must be disposed; the solids handling facilities are a frequent source of problem. Regenerable dry systems are often expensive to build because they employ swing adsorbers. While one adsorber train is capturing sulfur, the other is undergoing regeneration. The valving required to effect the adsorber changes must be able to withstand the temperature and solids content of the flue gas. Solids present in the flue gas stream coat the adsorbent if it is stationary and dilute the absorbent if it is fluidized. The net result is reduced SOx removal efficiency. Some of the regenerable systems require high purity desorption gas.
• In attempts to reduce sulfur oxide (SOx) emissions from FFC units, SOx transfer additives have been injected into the circulating catalyst inventory. Similar technology has been suggested for operating selective vaporization units - see U. S. 4,325,815 (Bartholic).
• The SOx transfer additives are fluidizable particles of of material capable of reacting with an oxide of sulfur in an oxidizing atmosphere,or an environment which is not substantially reducing, to form solid compounds capable of reduction in the reducing atmosphere of the FCC reactor to yield H₂S. Upon such reduction, the sulfur leaves the reactor as gaseous H₂S and organic compounds of sulfur resulting from the cracking reaction. Since these sulfur compounds are detrimental to the quality of motor gasoline and fuel gas by-products, the catalytic cracker is followed by downstream treating facilities for their removal. Thus the gaseous fractions of cracked product may be scrubbed with an amine solution to absorb H₂S which is then passed to facilities for conversion to elemental sulfur, e.g. a Claus plant. The additional H₂S added to the cracker product stream by chemical reduction in the reactor of the solid sulfur compounds formed in the regenerator imposes little additional burden on the sulfur recovery facilities. It has been proposed to utilize this transfer concept to remove oxides of sulfur from waste gases other than FCC flue gas by introducing such gases into the regenerator of an FCC unit operated with an inventory of SOx adsorbent and removing the sulfur from the circulating inventory in the FCC riser where a reducing atmosphere exits.
• Discussion of a variety of oxides which exhibit the property of combining with SOx and thermodynamic analysis of their behavior in this regard are set out by Lowell et al., SELECTION OF METAL OXIDES FOR REMOVING SOx FROM FLUE GAS, IND. ENG. CHEM. PROCESS DES. DEVELOP., Vol. 10, No.3 at pages 384-390 (1971).
• An early attempt to reduce SOx emission from catalytic cracking units, as described in U. S. 3,699,013, involves adding particles of a Group II metal compound, especially calcium or magnesium oxide, to a cracking unit cycle at a rate at least as great as the stoichiometric rate of sulfur deposition on the cracking catalyst, the additive preferably being injected into the regeneration zone in the form of particles greater than 20 microns. Particle size was chosen to assure a relatively long residence time in the unit. In putting the invention into practice, the Group II metal compound is recycled at least in part between the reactor and the regenerator, the remainder leaving the cycle along with catalyst fines entrained in regenerator flue gas. Subsequently it was proposed to incorporate the alkaline earth metal compound in the cracking catalyst particles by impregnation in order to minimize loss of the sulfur acceptor in the regenerator flue gases - see U. S. 3,835,031. This patent apparently recognizes the need for free oxygen for binding SOx with a Group II metal oxide since the equations for the reaction taking place in the regenerator are summarized as follows:
  MgO + SO₂ + 1/2 O₂ = MgSO₄
  Similar use of reactive alumina either as a discrete fluidizable entity or as a component of catalyst particles is described in U. S. 4,071,436, 4,115,250 and 4,115,251. Use of oxidants including platinum or chromium as adjuncts to alumina is suggested in these patents. Similar technology has been suggested for operating selective vaporization units - see U. S. 4,325,815 (Bartholic).
• In the prior art techniques aforementioned, emphasis was on reversibly reacting sulfur oxides in the flue gas, and doing so while the gases were still in the regenerator. Since the sulfur loaded particles were carried to the reactor to be converted to gaseous hydrogen sulfide under the reducing atmosphere created by the cracking operation, the agents used to bind and then release sulfur were necessarily limited to those capable of doing so under the constraints of temperature and time imposed by the operation of the reactor and the regenerator.
• With units operating with high sulfur feedstock, relatively large amounts of sulfur acceptors having high unit capacity to adsorb SOx are needed to accomplish reductions in sulfur oxide levels. This will result in appreciable dilution of the active catalyst in the cracking reaction cycle whether the sulfur acceptor is a part of the catalyst particles or is present as discrete entities circulated with catalyst inventory. A basic limitation is that conditions of time and temperature for operating cyclic cracking units, especially heat balanced FCC units, are geared to maximizing production of desired products,and conditions that will favor this result are by no means those that are optimum for reversibly reacting sulfur oxides in the regenerator and carrying the sulfur back to the reactor for conversion at least in part to hydrogen sulfide. Such procedures offer promise as means to reduce SOx emissions from refineries but they leave much to be desired. The technique has had limited commercial success, because SOx removal activity decreases rapidly with time presently available SOx transfer agents.
• In U. S. 4,448,674 (Bartholic) there is described a system for application of the technique of binding SOx in FCC regenerator gases operated with limited air and producing a flue gas containing substantial amounts of carbon monoxide, i.e. a reducing atmosphere. In such cases, the flue gas temperature is reduced to a level at which ignition of CO is inhibited, air is injected to provide an oxidizing atmosphere and the cooled stream containing carbon monoxide and oxygen is contacted with the regenerated catalyst in a transport line under turbulent conditions to promote pick-up of SOx. As described in the patent, the effluent from that contact is passed through a valve and then sent to a CO boiler to recover the fuel value of CO by combustion at higher temperature. The agent to bind SOx is separated from gases in a precipitator and is not regenerated. To the contrary, regenerable agents are avoided because they will release oxides of sulfur in the CO boiler.
• U. S. 4,001,375 (Longo) describes a process for the removal of sulfur oxides from gases by a regenerable sorbent composed of a cerium oxide sorbent such as cerium oxide supported on alumina. Contact of gas with sorbent is in a fixed bed. When the sorbent is loaded to a desired level it is transferred to another fixed bed in which hydrocarbon gas or hydrogen in admixture with "steam or other inert gas" is used to regenerate the sorbent. The patent teaches that during regeneration the desorbed species is initially sulfur dioxide;when about 50% of the sulfur is removed, the desorbed species becomes H₂S. Referring to an example in the patent, it is stated that "the regeneration step is almost instantaneous relative to the slower rate of SO₂ pickup.
• U. S. 4,325,811 (Sorrentino) describes a process using a regenerable sulfur oxide adsorbent to control SOx emission of the regenerator of an FCC unit in which a stream of particles including particles of the adsorbent is withdrawn from the regeneration zone and passed to a reducing zone to release adsorbed SOx. The stream of particles is then circulated back to the regeneration zone and recirculated between the reaction and the regeneration zone. In the reducing zone temperature range from about 590°C. (1094°F.) to about 820°C (1508°F.). The preferred reducing gas comprises a mixture of steam with hydrogen or hydrocarbon.
• Illustrative of other patents relating to regenerable Sox adsorbents adapted for use in FCC units are: U. S. 4,153,534 (Vasalos); U. S. 4,153,535 (Vasalos et al); U. S. 4,071,436 (Blanton); U. S. 4,115,249 (Blanton et al); U. S. 4,166,787 (Blanton et al); U. S. 4,146,463 (Radford et al); U. S. 3,835,031 (Bertolacini et al); Canadian Patent 1,154,735 (Brown et al); U. S. 4,423,091 (Bertolacini et al); U. S. 4,495,304 and U. S. 4,495,305 (Yoo et al); U. S. 4,529,574 (Wang); U. S. 4,459,371 and U. S. 4,459,372 (Hobbs et al); and U. S. 4,381,991 (Bertolacini et al).
• A recent publication of Andersson et al, "SOx Adsorption/Desorption Processes on γ-Alumina for SOx Transfer Catalsyt," Applied Catalysis, 16 (1985) 49-58, describes thermogravimetric investigations into SOx adsorption/desorption for different conditions purported to simulate FCC operations using γ-alumina as the adsorbent. It is noted, however, that conclusions in the paper regarding desorption of SOx in an FCC riser are based on thermogravimetric desorption tests using alumina that was not coked.
• A fluidized bed system for reducing NOx and SOx is described in a publication of Haslbeck et al. "The NOXSO Process Development; an Update," prepared for the Ninth EPA-EPRI Symposium on Flue Gas Desulfurization, June 4-7, 1985. A regenerable adsorbent is used.
• The present invention provides a process for cracking a sulfur containing hydrocarbon feedstock by introducing the feedstock into contact in a cracking riser with fluidized cracking catalyst inventory including SOx transfer agent, feeding spent catalyst inventory from the riser to a combustion regenerator, and recycling hot regenerated catalyst inventory to the riser, characterised by charging hot regenerated catalyst inventory to the riser upstream of the hydrocarbon feedstock introduction and into contact with reducing gas and H₂O which lift said hot regenerated catalyst inventory in the riser and desorb adsorbed oxides from said transfer agent before contact with the hydrocarbon feedstock. In one embodiment it provides a process for cracking a sulfur containing hydrocarbon feedstock in a fluid riser cracking unit operated with a regenerator operated in full combustion mode and a circulating cracking catalyst inventory including SOx transfer agent which circulates between the riser and the regenerator, the process being characterised by charging regenerated catalyst including SOx transfer agent at a temperature above 1100°F into the lower part of the riser into contact with reducing gas and water or stream at sufficient gas velocity to lift said regenerated catalyst in the riser, and introducing such hydrocarbon feedstock into the riser at a distance sufficiently downstream from the introduction of regenerated catalyst that the reducing gas residence time in the riser before said feedstock introduction is sufficient for desorption of substantially all of the adsorbed oxides of sulfur. In another it provides a process for cracking sulfur containing hydrocarbon feedstock in a fluid riser cracking unit operated with a regenerator operated in full combustion mode and a circulating cracking catalyst inventory including SOx transfer agent which circulates between the riser and the regenerator, characterised by mixing in the lower section of the riser (a) regenerated catalyst including SOx transfer agent with (b) reducing gas and steam or water so that the resulting mix temperature is at least 1050°F for sufficient time and with sufficient reducing gas and water to desorb substantially all of the adsorbed oxides of sulfur as H₂S before introduction of the hydrocarbon feedstock into the riser downstream of said mixing/desorption section.
• Thus SOx emissions from catalyst regenerators of FCC units that utilize hydrocarbon feedstock contaminated with sulfur and operate in the complete combustion mode with a circulating inventory of fluidizable cracking catalyst including an SOx transfer agent can be reduced by simple modification of the conventional riser structure of an FCC unit to achieve multiple benefits, e.g. moving the feedpoint for introducing hydrocarbons feedstock upwardly on the riser, e.g. to the midpoint, and injecting reducing gas and steam or water near the base of the riser to lift the hot regenerated catalyst including the SOx transfer agent with adsorbed SOx to the feed point while simultaneously desorbing adsorbed SOx from the agent during transport by the reducing gas mixed with water vapor.
• The SOx transfer agent can be a component of the cracking catalyst particles and/or can be contained in particles separate from the catalyst particles.
• Practice of the present invention results in desorption of sorbed SOx from the circulating catalyst inventory under conditions more favorable than those prevailing in a riser operated in conventional manner. In conventional operation of FCC units using SOx transfer agents, the regenerated circulating catalyst inventory including the transfer agent is coked within milliseconds after contact with feed in the riser. The coke coating of the circulating inventory does not facilitate access of the reducing gases to the particles containing transferred SOx. Furthermore, we have found that temperatures above 1100°F and sufficient residence time under reducing conditions and in the presence of water vapor result in markedly superior desorption of transferred SOx. However, the circulating inventory in an FCC does not remain at such temperatures for a sufficient time in the riser cracker since within milliseconds the temperature of the inventory decreases to within about 30° F of the riser outlet temperature (generally 925-1000°F) as a result of heat transfer with the charge of hydrocarbon to the riser. In practicing our invention, in contrast, the circulating inventory remains hot longer at the base of the riser because the amount of heat required to increase the reducing gas and water vapor to SOx desorption conditions with the hot regenerated circulating material is much less than that required to heat and vaporize the FCC liquid feed. Therefore the solids with transferred SOx are provided with a sufficiently long residence time at temperatures greater than 1050°F in the presence of a reducing gas and water vapor, without significant coke deposition on the regenerated circulating material, by modification of the riser to enhance desorption of SOx. Our invention provides a means to desorb at least at much SOx as is adsorbed in the regenerator and avoids the possibility that the transfer agent will be unable to adsorb additional amounts of SOx and thus deactivate by becoming SOx capacity-limited.
• The accompanying drawing illustrates the modification of an existing riser by adding an additional lower riser section to provide an SOx transfer zone in below the cracking zone. It is within the scope of the invention, however, to practice the invention with risers of sufficient height by relocating the feed injection point upwardly without adding an additional riser section.
• Referring to the figure, sulfur-laden adsorbent and regenerated catalyst (A) at a temperature above 1100°F flow through the existing regenerated catalyst standpipe. A mixture of one or more reducing gases (B) and steam of water (C) is admitted to the bottom of a new section of reactor riser. The hot regenerated catalyst including the SOx transfer agent is mixed with reducing gas and steam or water and the hot mixture passes through this section where SOx is desorbed. Sufficient steam, water or water vapor and reducing gas are mixed with the catalyst at resultant temperatures in excess of 1050°F for a sufficient time to desorb substantially all of the adsorbed oxides as H₂S. A variety of reducing gases is contemplated. Nonlimiting examples are hydrogen, carbon monoxide, and light hydrocarbons such as butane, propane and ethane. The reducing gas can be a recycled product gas. The clean adsorbent, H₂S, reducing gas, water vapor and regenerated catalyst then exit the SOx riser (D) and contact the FCC feed (E). Hydrogen sulfide and hydrocarbon products are separated from the adsorbent and catalyst in an existing solids separation device downstream from the riser. Adsorbent and spent catalyst are then conveyed to an existing regenerator vessel. Sufficient air is added to the regeneration vessel to completely combust the coke on adsorbent and spent catalyst. Sulfur oxides are subsequently adsorbed on the SOx adsorbent. Sulfur laden adsorbent and regenerated catalyst are discharged through the standpipe from which they pass to the riser.
• Regenerator temperatures of the regenerator (not shown) are always above 1100°F when regeneration is in the full combustion mode for most effective SOx transfer and are usually above 1300°F. Regenerator temperatures may be 1600°F or even higher.
• The superficial gas velocity in the SOx riser (D) at the exit is 3.5 feet per second or higher. The height of SOx riser is selected to provide a gas residence time of greater than 1 second in (D), typically 2 to 3 seconds to give adequate mixing and contact. Times of the order of 10 seconds may be used.
• Typical volumetric ratio of desorption gas to desorption water is 50000:18.
• Known SOx transfer agents can be used in practicing the invention and the transfer agent may be a component of the fluidizable cracking catalyst particles and/or be present as separate particles. Conventional cracking catalysts can be used. Present day FCC cracking catalysts contain zeolitic molecular sieves of the synthetic faujasite type. A presently preferred transfer agent is composed of a minor amount of one or more rare earth metal oxides, especially lanthanum or cerium rare earth metal, supported on a major amount of attrition-resistant particles of alumina or a magnesia-alumina spinel. An example is SOx transfer agent composed of about 20% by weight of lanthanum-rich mixed rare earth oxides supported on particles of alumina and having a fresh surface area (BET method) above 100 m²/g. In some cases a small amount of precious metal is also included in the circulating catalyst inventory to facilitate adsorption of SOx by the transfer agent. The proportion of SOx transfer agent (SOx adsorbent) to particles of zeolitic cracking catalyst varies depending inter alia on the SOx capacities of the adsorbent and cracking catalyst particles and the cracking activity of the cracking catalyst component.

Claims (10)

1. A process for cracking a sulfur containing hydrocarbon feedstock by introducing the feedstock into contact in a cracking riser with fluidized cracking catalyst inventory including SOx transfer agent, feeding spent catalyst inventory from the riser to a combustion regenerator, and recycling hot regenerated catalyst inventory to the riser, characterised by charging hot regenerated catalyst inventory to the riser upstream of the hydrocarcbon feedstock introduction and into contact with reducing gas and H₂O which lift said hot regenerated catalyst inventory in the riser and desorb adsorbed oxides from said transfer agent before contact with the hydrocarbon feedstock.

2. A process according to claim 1 wherein the temperature of the regenerated catalyst inventory in the riser is initially at least 1050°F, preferably at least 1100°F.

3. A process for cracking a sulfur containing hydrocarbon feedstock in a fluid riser cracking unit operated with a regenerator operated in full combustion mode and a circulating cracking catalyst inventory including SOx transfer agent which circulates between the riser and the regenerator, the process being characterised by charging regenerated catalyst including SOx transfer agent at a temperature above 1100°F into the lower part of the riser into contact with reducing gas and water or steam at sufficient gas velocity to lift said regenerated catalyst in the riser, and introducing such hydrocarbon feedstock into the riser at a distance sufficiently downstream from the introduction of regenerated catalyst that the reducing gas residence time in the riser before said feedstock introduction is sufficient for desorption of substantially all of the adsorbed oxides of sulfur.

4. A process for cracking sulfur containing hydrocarbon feedstock in a fluid riser cracking unit operated with a regenerator operated in full combustion mode and a circulating cracking catalyst inventory including SOx transfer agent which circulates between the riser and the regenerator, characterised by mixing in the lower section of the riser (a) regenerated catalyst including SOx transfer agent with (b) reducing gas and steam or water so that the resulting mix temperature is at least 1050°F for sufficient time and with sufficient reducing gas and water to desorb substantially all of the adsorbed oxides of sulfur as H₂S before introduction of the hydrocarbon feedstock into the riser downstream of said mixing/desorption section.

5. A process according to any preceding claim wherein the reducing gas residence time in the riser before feedstock is introduced is at least 1 second.

6. A process according to any preceding claim wherein the reducing gas residence time is up to 10 seconds.

7. A process according to any preceding claim wherein the reducing gas comprises at least one component selected from hydrogen, carbon monoxide, and light hydrocarbons.

8. A process according to any preceding claim wherein the regenerated catalyst temperature is at least 1300°F, e.g. 1300 to 1600°F.

9. A process according to claim 1 wherein the cracking catalyst comprises zeolitic molecular sieve.

10. A process according to any preceding claim wherein the SOx transfer agent comprises at least one rare earth compound, preferably supported on particles of alumina or alumina-containing spinel.