RFCC Process Technology Manual

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(1)UOP Fluid Catalytic Cracking Process Process Technology Manual. ORPIC Sohar, Oman September 2012. – LIMITED DISTRIBUTION – This material is UOP LLC technical information of a confidential nature for use only by personnel within your organization requiring the information. The material shall not be reproduced in any manner or distributed for any purpose whatsoever except by written permission of UOP LLC and except as authorized under agreements with UOP LLC..

(2) 157048 Table of Contents Page 1. FCC PROCESS TECHNOLOGY. TABLE OF CONTENTS I.. INTRODUCTION. II.. PROCESS FLOW Reactor Regenerator Main Column Gas Concentration and Recovery. III.. PROCESS CONTROL Reactor Regenerator Main Column Gas Concentration. IV.. EQUIPMENT Process Equipment and Its Use Metallurgical Corrosion. V.. FLUIDIZED SOLIDS Theory Applications to Fluid Catalytic Cracking. VI.. CATALYST History Modern FCC Catalysts Time and Temperature Effects Poisons Catalyst Management Catalyst Properties and Testing. VII.. PROCESS VARIABLES Reactor and Regenerator Process Variables Feedstock. VIII.. PROCESS CALCULATIONS FCC Flow Corrections and Mass Balance Liquid Product Cutpoint Corrections Reactor and Regenerator Heat Balance FCC Unit Mechanical Summaries Additional FCC Unit Calculations.

(3) 157048 Table of Contents Page 2. IX.. FEED AND PRODUCT TREATING Feed Treating Product Treating – Reasons and Methods. X.. ANALYTICAL METHODS Minimum Sample Size Typical Sampling Schedule Outline of FCCU Laboratory Methods. XI.. PROCEDURES Refractory Dryout Startup Shutdown Emergencies Catalyst Handling FCC Unit Evaluation. XII.. SAFETY General Additional Safety Precautions for Entering Vessels High Temperature Problems Chemical Hazards. XIII.. ENVIRONMENTAL Emissions Sources and Solutions.

(4) 157048 Introduction Page 1. Introduction UOP Company History For more than 80 years, UOP has been one of the world’s leading licensors of new and innovative technology. Today, UOP continues in this role with 30 offices on 4 continents and 9 manufacturing facilities worldwide. UOP currently licenses and designs more than 60 different processes and has a total of 5,500 units licensed worldwide. For the last 50 years, the fluid catalytic cracking (FCC) process has been an important and successful part of UOP's licensing activities.. The Early Years UOP was founded in 1914 as the National Hydrocarbon Company on the strength of patent rights developed from the pioneering work of Jesse A. Dubbs, a California inventor. The company was financed by a noted Chicagoan, J. Ogden Armour. In 1915, the company name was changed to Universal Oil Products Company. From the beginning, the goal of the company was to develop and commercialize technology for license to the petroleum refining industry. Under the direction of C. P. (Carbon Petroleum) Dubbs, son of Jesse Dubbs, research and development work continued at the company's small site near Independence, Kansas, where the famous Dubbs Thermal Cracking process was successfully demonstrated in 1919. The then-revolutionary process became the foundation of UOP's rapid growth and its early worldwide recognition by the industry. The early period of growth was ably directed by its president, Hiram J. Halle, and by Dr. Gustav Egloff, one of the world’s leading petroleum chemists. In 1931, UOP established its headquarters in Chicago and its research laboratories in nearby Riverside, Illinois. That same year the ownership of UOP passed to a consortium of its major licensees, led by Shell and Standard Oil of California..

(5) 157048 Introduction Page 2. During this stage, the company benefited immensely by the addition to its research staff of Prof. Vladimir Ipatieff, a famous Russian scientist known internationally for his work in high-pressure catalysis. His contributions in catalytic chemistry gave UOP a position of leadership in the development of catalysis as applied to petroleum processing. The first project of Ipatieff and his research team was catalytic polymerization. Other eminent scientists were also attracted to UOP’s research center in Riverside during this period. With the outbreak of World War II, UOP scientists and engineers focused their knowledge and talents on developing new catalytic processes, notably alkylation that helped meet wartime energy requirements, especially for aviation fuel. UOP also cooperated with other companies to develop the FCC process. In 1944, the owners of UOP divested themselves of their holdings in the company, and UOP’s stock was placed in trust. The American Chemical Society was named as the beneficiary. Thus, the Petroleum Research Fund was created with the understanding that income from the trust was to be used for advanced scientific education and fundamental research in the petroleum field. In spite of some financial and legal setbacks suffered by UOP during this period, strong management succeeded in steering the company back to its original course: taking creative research from concept to commercial reality. UOP was recognized as a company employing the world’s most knowledgeable scientific and technical personnel, who understood petroleum refining and the need for improved processing methods and techniques. In 1949, UOP's research staff developed a radically different refining process that used a catalyst containing platinum. Called the Platforming™ process, it revolutionized the art of reforming to produce gasoline with substantially improved octane number. The process was also instrumental in making benzene available in a quality and quantity never before realized on a commercial scale. With the Platforming™ process and other innovative processes, UOP became a vital contributor to the emergence and growth of the petrochemical industry..

(6) 157048 Introduction Page 3. In the early 1950s, UOP also began to manufacture its own proprietary catalysts and a variety of refining chemicals at a newly constructed plant in Shreveport, Louisiana. Later UOP built manufacturing plants at McCook, Illinois; Brimsdown, U.K.; and other locations. In 1952, UOP moved its headquarters and engineering activities to Des Plaines, a suburb of Chicago. Soon after, the construction of a new research center at the same location was begun.. The Recent Era In 1959, UOP assumed its fourth different corporate form when it was sold to the public for the first time in its history. As a publicly owned company, UOP entered a new era marked by growth and diversification. The 1960s saw UOP grow from essentially a process-licensing company to a diversified corporation through many acquisitions and mergers with other companies. By 1975, UOP Inc. included more than 20 different divisions involved in such areas as aerospace and automotive technology. During the 1960s and 1970s, UOP's tradition of innovative process development and commercialization continued with the licensing of the first Sorbex™ simulated moving-bed countercurrent adsorption process in 1961 and the introduction of UOP's CCR Platforming™ process early in the 1970s. In 1975, Signal Companies Inc. acquired 50.5% of UOP and in 1978 acquired the remaining 49.5%, making UOP a wholly owned subsidiary of the company. When the Signal Companies merged with Allied Corporation in 1985, UOP Inc. became a subsidiary of Allied-Signal Inc. As the result of reorganizations and restructuring by its parent companies during the 1980s, UOP’s business scope was refocused on the development and licensing of process technology and the marketing of products associated with its licensing activities. Of the 20 different divisions, only the Process Division and UOP Management Services remain in the present UOP..

(7) 157048 Introduction Page 4. In 1988, Allied-Signal entered into an agreement with Union Carbide Corporation that resulted in the creation of a unique joint venture company called simply UOP. The new UOP combined the resources of Allied-Signal’s UOP Inc. with the Catalysts, Adsorbents and Process Systems (CAPS) Division of Union Carbide. The joint venture brought together in synergistic union the strong R&D traditions of both companies. The joint venture now contains the new materials R&D of the CAPS Union Carbide researchers and the scale-up and commercialization skills of UOP research. In addition, the joint venture brings together the commercial experience and worldwide marketing presence of both partners. The result is unprecedented growth for UOP and the development of valuable new technologies, products, and services for its customers. Table 1 summarizes some of the historical highlights of UOP as a process technology company.. Table 1 UOP's History 1914. National Hydrocarbon Company formed to hold Jesse Dubbs patents for a process to recover heavy oil from water. 1915. Name changed to Universal Oil Products Company -patents for Dubbs cracking process issued. 1921. Dubbs continuous cracking process commercialized. 1930. Ipatieff joins UOP beginning a wave of new process developments: alkylation, catalytic polymerization, C4 isomerization. 1941. FCC technology developed. 1949. Platforming™ introduced, many aromatics processes followed. Late 1950s 1961 Early 1970s. Hydrocracking introduced First Sorbex™ unit licensed CCR Platforming™ introduced. 1988. UOP merged with the EP&P and CAPS groups of Union Carbide. 1995. UOP acquires the Unocal hydroprocessing business.

(8) 157048 Introduction Page 5. In the last 20 years, UOP has developed and commercialized a variety of new and innovative processes for the refining and petrochemical industry including the Penex™, Molex™, BenSat™, Oleflex™, Ethermax™, Merox™, Styro-Plus™, Alkylene™, Isal™, Isomar™ and Detal™processes. UOP transfers this technology to its clients through its licensing activity. In the technology transfer process, UOP licenses technology; assists in the planning, design, engineering and commissioning of new installations; provides management services and advises on the efficient performance of processing facilities throughout the world. Behind the successful performance record of UOP is a highly qualified and strong team continuously at work on ideas and projects. The scientific disciplines are strongly represented in UOP's team of personnel. UOP has about 4,000 employees worldwide. With a wide array of highly specialized talents, UOP offers its clients the complete capability necessary in meeting the demands of today, and the challenges of the future. UOP licenses or maintains a position of technical expertise for more than 60 different processes in the petroleum and petrochemical industry. Approximately 175 process units are licensed yearly, and to date UOP has licensed more than 5,500 individual process units and provided technical know-how in designs for more than 1,000 additional non-licensed units. UOP presently holds in excess of 9,000 unexpired patents. UOP's worldwide licensing activities are supported by a network of offices and representatives. UOP is centered in Des Plaines, Illinois, and has a district office in Houston. UOP Limited, a 100% UOP owned subsidiary for operations in Europe, Africa and the Middle East, has its main European office in Guildford (near London) and district offices in New Delhi, Jakarta, Jeddah, Beijing and Moscow. UOP Asia Pacific, located in Tokyo, is an affiliate company of UOP for the licensing of UOP processes in Japan and certain other areas in the Far East and Southeast Asia..

(9) 157048 Introduction Page 6. UOP has catalyst manufacturing facilities in the United States and in Europe. UOP Asia Pacific operates a catalyst plant in Japan. The international scope of UOP activities is evidenced by the fact that process units have been designed for installation in more than 80 countries around the world. UOP activities related to these installations have ranged from preparation of engineering designs for single process units to extensive planning studies involving market analyses, feasibility and optimization studies, designs for entire grassroots refineries (both process units and offsites), and complete plant commissioning services. The services provided by UOP for these units includes plant design, inspection, commissioning, performance testing, and training of refinery operating personnel. Since 1955, UOP has provided, or is providing, engineering designs for more than 125 grassroots refineries and petrochemical complexes. UOP also provided design specifications for all offsite equipment for many of these installations.. Historical Origins of FCC Technology The advent of the petroleum refining industry can be traced to the rapidly increasing demand for kerosene to fuel kerosene lamps for lighting in the latter half of the 1800s. With the invention of electric lighting and the automobile in the early 1900s, the high value product of petroleum refining shifted from kerosene to gasoline. The increasing demand for gasoline soon outstripped the availability of straight-run gasoline from crude oil distillation. This shortage of gasoline provided the impetus for the development of technologies to increase the gasoline yield from a barrel of crude oil. Table 2 shows a summary of the progression of cracking technology which has led to the FCC process as we know it today..

(10) 157048 Introduction Page 7. Table 2 Historical Origins of Fluid Catalytic Cracking 1913 - 1936. Thermal cracking  Burton thermal cracking process (1913)  Dubbs thermal cracking process (1915)  Current use – visbreaking, coking. 1936 - 1941. Fixed-bed catalytic cracking  Houdry Process Company (1931) - Multiple reactors -- cyclic process (1937) - Silica-alumina catalyst (acid-activated clay). 1941 - 1955. Moving-bed catalytic cracking  Thermofor catalytic cracking (TCC) developed by Socony-Vacuum (Mobil)  Houdryform catalytic cracking - Continuous process - Macro-catalyst, moving bed. 1942 - Present Fluid catalytic cracking (FCC)  Joint development (1938) - Continuous process - Micro-catalyst, fluidized bed. Thermal Cracking The first thermal conversion process was the Burton process first practiced commercially in 1913 by Standard Oil of Indiana. In the original Burton process, oil was exposed batch-wise to high temperature at elevated pressure to achieve thermal conversion to lighter products. Because of the batch nature of the Burton process, commercial units contained a large number of individual cracking stills in order to achieve acceptable daily throughputs..

(11) 157048 Introduction Page 8. Following the commercialization of the Burton process, the Dubbs thermal cracking process was developed and patented in 1915 (UOP). The Dubbs process was a continuous process for the thermal conversion of oil to lighter products at elevated temperature and pressure. The Dubbs process was widely used in refineries through the 1920s and into the 1930s. Thermal cracking processes continue to be used in refining today. Examples of currently used thermal processes are visbreaking and various forms of coking.. Fixed-Bed Catalytic Cracking In the mid 1920s, a French mechanical engineer and racecar enthusiast named Eugene Houdry became interested in gasoline quality. After the trial and error screening of hundreds of catalyst formulations, Houdry found that acid-activated clay (silica and alumina) was an effective catalyst for cracking heavy oil to lighter products, particularly high octane gasoline. In 1931, Houdry, in partnership with Socony-Vacuum (now Mobil), founded the Houdry Process Company to develop Houdry's fixed-bed catalytic cracking process. The Houdry catalytic cracking was a cyclic process which typically used four timephased reactors, each of which cycled through a sequence of steps outlined below: 1. 2. 3. 4.. Hot heavy oil is cracked by contact with a fixed bed of catalyst. The reactor is purged to remove hydrocarbon. Coke deposited on the catalyst is burned off with air. The combustion gases are purged from the reactor and the reactor is ready to begin the next cracking cycle.. A number of technical innovations were required to make the Houdry cracking process successful. Among these were the development of automatic valves and the use of control algorithms to control the reaction-regeneration cycles. Many of the innovations associated with the commercialization of the Houdry cracking.

(12) 157048 Introduction Page 9. process were considered revolutionary in the field of process engineering at the time they were first introduced. The Houdry catalytic cracking process was first commercialized at the Sun-Marcus Hook refinery in 1937. The Houdry process was technically attractive to refiners and by 1940, 14 commercial Houdry units were in operation. Interest in the Houdry process declined after 1941 because of further advances in catalytic cracking technology.. Moving-Bed Catalytic Cracking The next advance in catalytic cracking was the development of a continuous moving-bed cracking process. The Thermofor Catalytic Cracking (TCC) and Houdryform Catalytic Cracking (HCC) processes were developed in parallel in the 1940s and early 1950s. Both processes used a similar concept and had approximately equal success. In the TCC process, the catalyst pellets continuously move through the reactor to the regeneration vessel and are then returned to the reactor. The key to the TCC process was the Thermofor kiln used to regenerate the spent catalyst (the kiln had been originally developed to burn coke off of Fuller’s earth used to filter lube oils). In the TCC process, regenerated catalyst flows by gravity from a surge vessel elevated above the reactor, into the reactor vessel where the catalyst contacts hot oil and the cracking reactions take place. The air environment of the catalyst surge vessel is buffered from the hydrocarbon environment of the reactor by steam injected into the catalyst transfer line. Both the hydrocarbon vapors and catalyst flow down through the reactor to a lower section where the cracked products exit the reactor through separation pipes. The spent catalyst continues to flow by gravity down through a steam stripping zone into the regeneration kiln where coke is burned off the spent catalyst with air. The steam stripping zone also serves to provide a barrier between air in the regenerator and hydrocarbon in the reactor. In early TCC units, the hot regenerated catalyst pellets were mechanically conveyed.

(13) 157048 Introduction Page 10. back up to the catalyst surge vessel by bucket elevators. Later units employed pneumatic air lift systems to transfer the regenerated catalyst back up to the surge vessel. Socony-Vacuum was the principle developer of the TCC process and the first semi commercial unit started up at the Paulsboro refinery in 1941. The TCC units were licensed and operated by Socony-Vacuum and others from 1941 to about 1955 when the TCC gave way to the more versatile FCC process developed in the during the late 1930s and early 1940s. A few TCC units still continue to operate today.. The FCC Process Early development of the FCC process took place late in the 1930s. A number of motivations were behind the development of the FCC process. Among these were the high fees required to license the Houdry cracking process, the diffusion and heat transfer limitations associated with both the Houdry fixed-bed process and the TCC process (both used large size catalyst pellets), and the increasing demand for high octane aviation gasoline brought on by World War II. Initial FCC process development efforts were led by Standard Oil of New Jersey (now Exxon) in association with two researchers from the Massachusetts Institute of Technology, Warren Lewis and Edwin Gilliland (consultants to Standard-NJ). Lewis and Gilliland had found that under the proper aeration conditions, finely divided solid particles (powders) could flow through pipes and in many respects act similarly to liquids. This was the advent of fluidization. The use of finely divided cracking catalyst offered a means of overcoming the diffusion and heat transfer limitations encountered with the large size catalyst pellets used in the earlier catalytic cracking processes. In 1938, Standard-NJ and some of the other major oil companies, as well as M. W. Kellogg Co. and Universal Oil Products (UOP), formed Catalytic Research Associates (CRA) to jointly develop a fluidized catalytic cracking technology. The first commercial-scale (13,000 BPD) FCC unit, designated the Model I, started up at.

(14) 157048 Introduction Page 11. Standard-NJ's Baton Rogue refinery in May 1942. Two other Model I FCC’s were designed but were not built as the improved Model II FCC design came very quickly. When Standard-NJ announced the construction and imminent startup of the first FCC Model I, they also announced that Universal Oil Products (UOP) and M. W. Kellogg would be designing and licensing the new FCC technology. In the threeyear period between 1942 and 1945, 34 new FCC units came on stream in the refineries of 20 different oil companies. The installed capacity of these new FCC units was over 500,000 BPD. Thirteen of these units were licensed from UOP. Following the commercialization of the Model I and Model II FCC units within the CRA partnership, the FCC unit design and development diverged with the partner companies largely going their separate ways with regard to future FCC technology development and commercialization.. UOP and Fluid Catalytic Cracking During the 1940s, military requirements resulted in widespread commercialization when UOP designed about 40% of the 34 units that were built and operated. Following this period, UOP was in the forefront with commercialization of the "stacked" FCC unit design which featured a low-pressure reactor stacked directly above a higher pressure regenerator. The stacked design not only met the economic needs of smaller refiners, it was a major step toward shifting the cracking reaction from the dense phase of the catalyst bed to the dilute phase of the riser. In the mid-1950s, UOP introduced the "straight-riser" or side-by-side design. In this unit, the regenerator was located near ground level with the reactor to the side in an elevated position. Regenerated catalyst, fresh feed and recycle were directed to the reactor by means of a long, straight riser located directly below the reactor. Compared to earlier designs, product yields and selectivity were substantially improved. A major breakthrough in catalyst technology occurred in the mid-1960s with the development of the zeolitic catalysts. These catalysts demonstrated vastly superior activity, gasoline selectivity and stability characteristics compared to the amorphous.

(15) 157048 Introduction Page 12. silica-alumina catalysts then in use. The availability of the zeolitic catalysts served as the basis for most of the process innovations that have developed in recent years. The continuing sequence of advances in both catalyst activity and process design culminated in the most significant concept to date in the field of the FCC process – the achievement of transport-phase cracking entirely in the riser, or all-riser cracking. The key to all-riser cracking is the design of a system that initiates a plug-flow reaction and then stops the cracking reaction at the optimum yield of desired products. UOP commercialized a new design based on this concept in 1971. This design was also applied to existing unit revamps. Commercial results confirmed the expected advantages of the system compared to the older designs. The quick quench design provided the desired high selectivity to gasoline, reduced coke yield, and a reduction of secondary cracking of desired products to lighter, less valuable material. The next major improvement in the FCC technology was the development of catalysts and regenerator systems for the complete internal combustion of carbon monoxide (CO) to carbon dioxide (CO2). In 1973, an existing UOP unit was revamped to include a new combustor concept in regeneration technology to achieve direct conversion of CO within the unit. This was followed by the start-up in 1974 of a new FCC unit specifically designed to incorporate the combustor regenerator technology. This development in regenerator design and operating technique resulted in reduced coke yields, lower CO emissions which satisfy environmental standards and higher circulating catalyst activity that improved product distribution and quality. Table 3 summarizes some of the major achievements in UOP's FCC process technology development and commercialization..

(16) 157048 Introduction Page 13. Table 3 Milestones in FCC Technology 1942. UOP begins licensing the FCC Process. 1945. 13 Units licensed by UOP. 1947. UOP commercializes stacked unit design  Economical for small refiners  50 Stacked designs over 10-year period. 1950s. UOP commercializes side-by-side design  Straight riser  Better suited for larger units  Riser extension and termination (more reaction in riser). 1973. First complete combustion regenerator. 1983. First two-stage regenerator with external dense-phase cooling for highly contaminated resid feed commissioned. 1983. First elevated distributors commissioned. 1991 - 1995. Newest generations of highly contained riser termination devices commercialized (VDS™ and VSS™). 1994. First Optimix™ feed distributor commissioned. 1994. First MSCC™ unit commissioned. 2006. First AF™ Packing commissioned. Recent Developments Advances in riser termination devices occurred at a rapid rate in the 1980s to the mid 1990s. Early riser termination devices such as the open Tee resulted in very long residence times for the hydrocarbon products in the reactor vessel. This extended residence time resulted in nonselective thermal cracking and secondary catalytic cracking reactions. Recent improvements have resulted in better containment of the hydrocarbon vapor to the riser and therefore lower post riser residence time. This reduced delta coke and dry gas and improved gasoline selectivity. Early versions of these high containment riser terminations included the vented riser and.

(17) 157048 Introduction Page 14. SCSS (suspended catalyst solids separation) devices. In 1991, the first VDS™ (vortex disengager stripper) was commissioned. This technology further minimized the post-riser residence time resulting in further improvements in product yields. In 1995, the first VSS™ (vortex separation system) was commissioned. Improvements in feed distribution systems also occurred rapidly in the late 1980s and 1990s. Elevated, radially oriented feed distributors minimize nonselective thermal cracking reactions by providing more uniform feed/catalyst contacting with less back mixing than the earlier wye feed distributors. Acceleration zone technology which pre-accelerates the catalyst into a uniform, moderate density flow pattern for optimum oil penetration and uniform catalyst/oil contacting further improved the performance of the elevated feed distributors. The first UOP elevated feed distributors were commissioned in 1983. Developments in spray nozzle technology resulted in the Optimix™ feed distributor which has a smaller, more uniform oil droplet size and a spray pattern that distributes the oil uniformly over the entire riser area for superior catalyst/oil contacting and performance. The first Optimix™ feed distributor was commissioned in 1994. Since then, the number of refiners using Optimix™ feed distributors has grown to over 80. Resid processing in FCC units began in the mid-1970s. During this same period, reactor temperatures were being increased to maximize gasoline octane. The need for higher conversion, combined with the desire to process residue feeds significantly increased coke yields and ultimately limited the FCC regenerator capacity. The RCC®, or Reduced Crude Conversion, process was developed jointly by UOP and Ashland Oil in the late 1970s to address residue processing. It is an extension of UOP's FCC design experience that incorporates many innovations and modifications from the UOP-Ashland Oil development program. In addition to cold-flow modeling work, a large-scale pilot plant was constructed at Ashland's Catlettsburg, Kentucky refinery. Testing in this 200 BPSD plant examined processing variables and new mechanical designs on a wide range of residual feedstocks. In 1983, Ashland commissioned a 40,000 BPSD RCC unit at the Catlettsburg refinery..

(18) 157048 Introduction Page 15. Several major innovations from the pilot plant testing and first commercial design at Ashland have become the foundation of UOP's technical offering for catalytic cracking of residue feedstocks, including the following. • Acceleration zone and feed distribution system • Higher containment riser termination devices for quick disengagement • Two-stage catalyst regeneration • Catalyst cooler Since 1983, eight grass-root RCC units licensed by UOP have been commissioned. In addition, resid feedstocks are being processed in more than 30 existing UOP FCC units. In present times, the distinction between a gasoil FCC unit and a resid FCC unit has blurred to the point where most modern FCC units are capable of processing some level of resid. The term RFCC is used by UOP today to designate a new unit utilizing a 2 stage regenerator designed for the specific intent of processing resid feeds. Table 4 shows a brief summary of resid processing and UOP's activity in the area of resid processing..

(19) 157048 Introduction Page 16. Table 4 Resid Processing Milestones 1940s. Resid component added to feed. 1950s. Resid processing diminishes. 1975. Resid processing regains attractiveness  Market conditions favor increased efficiency in gasoline production  Technology and catalyst advances increase resid processing potential  UOP units begin processing resid/gasoil blends. 1976. UOP and Ashland Oil Cooperation  Research and development for reduced crude conversion  Semi-commercial demonstration. 1983. First RCC unit commissioned. 1984 - 2006. 8 New RCC units operating ->30 Units processing resid. Commercial Experience Since commercialization of the FCC process, UOP has licensed more than 210 units, or over 50% of all non-captive installations. More than 140 of these units continue to operate throughout the world. The superior technology and operational reliability built into UOP FCC units are some of the reasons why 58 refineries worldwide have licensed new UOP FCC units since 1980, which is more than all other licensors combined during this period. UOP's commercial activity in the FCC/RCC/MSCC™ processes since 1980 is as follows:     . 63 40 330 180 30+. New units licensed New units commissioned Revamps Major revamps Units processing resid with UOP technology.

(20) 157048 Introduction Page 17. Revamp activity is of equal importance in demonstrating technical expertise. In the period 1980-1998, UOP performed more than 330 unit revamps that encompassed virtually every major section of the FCC unit. This activity is vital to UOP's continuing advances in both process and design engineering. The depth of both grass-root and revamp experience gives UOP great capability to respond to the changing needs of the industry.. FCC Process Description The FCC process converts heavy crude oil fractions into lighter, more valuable hydrocarbon products at high temperature and moderate pressure in the presence of a finely divided silica/alumina based catalyst. In the course of cracking large hydrocarbon molecules into smaller molecules, a non-volatile carbonaceous material, commonly referred to as coke, is deposited on the catalyst. The coke laid down on the catalyst acts to deactivate the catalytic cracking activity of the catalyst by blocking access to the active catalytic sites. In order to regenerate the catalytic activity of the catalyst, the coke deposited on the catalyst is burned off with air in the regenerator vessel. One of important advantages of the FCC process is the ability of the catalyst to flow easily between the reactor and the regenerator when fluidized with an appropriate vapor phase. In FCC units, the vapor phase on the reactor side is vaporized hydrocarbon and steam, while on the regenerator side the fluidization media is air and combustion gasses. In this way, fluidization permits hot regenerated catalyst to contact fresh feed; the hot catalyst vaporizes the liquid feed and catalytically cracks the vaporized feed to form lighter hydrocarbon products. After the gaseous hydrocarbons are separated from the spent catalyst, the hydrocarbon vapor is cooled and then fractionated into the desired product streams. The separated spent catalyst flows via steam fluidization from the reactor to the regenerator vessel where the coke is burned off the catalyst to restore its activity. In the course of burning the coke a large amount of heat is liberated. Most of this heat of combustion is absorbed by the regenerated catalyst and is carried back to reactor by the fluidized regenerated catalyst to supply the heat required to drive the reaction side of the.

(21) 157048 Introduction Page 18. process. The ability to continuously circulate fluidized catalyst between the reactor and the regenerator allows the FCC unit to operate efficiently as a continuous process. The FCC units are large-scale processes and unit throughputs are typically in the range of about 10,000 to 130,000 barrels per day. This corresponds to catalyst circulation rates of around 7 to 130 tons per minute. The largest commercial FCC unit in operation was designed at 130,000 BPSD, pushed to ~184,000 BPSD, and in 2005 was revamped to a nominal 200,000 BPSD with a catalyst circulation rate in excess of 170 metric tons per minute. These large circulation rates of hot, abrasive catalyst constitute a very significant challenge to the mechanical integrity of the reactor, the regenerator and their associated internal equipment. Thus, mechanical design considerations are critical to the ultimate success of an FCC unit as a prominent refinery process unit. The main features of an FCC unit are:     . . Catalytic process Mechanical process Cracks heavy molecules to lighter ones Pressure: 15-45 psig (1-3 kg/cm2g) Temperature: Reactor: 915-1050F (490-565C) Regenerator: 1200-1450F (650-790C) Reaction and regeneration sections intimately linked by heat balance and catalyst circulation. FCC Process Feedstocks FCC units process heavy oil from a variety of variety of refinery flow schemes. Generally, the feed comes from either the refinery crude unit or vacuum unit and constitutes the fraction of the crude boiling in the range of 650 to 1000+°F (350 to 550+°C). There may be additional feed preparation units upstream of the FCC unit such as a hydrotreater or deasphalter. Figure 1 shows a schematic diagram of the possible refinery flows providing feed to an FCC unit..

(22) 157048 Introduction Page 19. In addition, the FCC units commonly process heavy fractions from other conversion units as part of the combined FCC feed blend. Examples of these types of streams are coker gasoil and hydrocracker fractionator bottoms. The types of heavy hydrocarbon streams that are commonly charged to an FCC unit are:        . Atmospheric gasoil Vacuum gasoil Atmospheric resid Coker gasoil Demetallized oil Hydroprocessed gasoil Hydroprocessed resid Lube oil extracts.

(23) 157048 Introduction Page 20. FCC Products The products obtained from the FCC unit are light hydrocarbon gases (C2-) which are normally used within the refinery as fuel gas, light olefins and paraffins (C3’s and C4’s) also referred to as LPG, gasoline, LCO and clarified oil commonly referred to as main column bottoms. In addition, flue gas is generated from the burning of coke in the regenerator. Heat is recovered from the flue gas and is used to make steam and in some cases power is also recovered from the flue gas in the form of electricity via a power recovery expander coupled to a motor/generator. Products produced from an FCC unit are:       . Light gas Light olefins LPG Light paraffins Gasoline Light cycle oil Main Column Bottoms Coke (burned in unit as fuel). . Most of the FCC product streams undergo further processing before leaving the refinery as marketable products. Figure 2 shows typical routes for the FCC product steams going to further processing and ultimately to blending into the refinery product pools..

(24) 157048 Introduction Page 21. Figure 2 Typical Use of FCC Products Flue Gas Reactor & Regen.. C3/C4 Paraffins Fuel Gas. Alkylation. LPG Merox Gasoline Gasoline Merox LCO CLO. Alkylate Gasoline Pool. C3/C4 Splitter Main Column & Gas Con. LPG Pool. MTBE Distillate Hydrotreater. Diesel Pool Heavy Fuel Oil Pool. The light liquid products from the FCC process are LPG and gasoline. The LPG from an FCC unit is highly olefinic and has become an increasingly valuable stream for further processing in the present movement toward reformulated gasoline and as petrochemical unit feedstocks. The FCC olefins are an important feedstock for the production of MTBE and alkylate as gasoline blending components and for the production of polypropylene. The FCC gasoline generally has good octane properties (90-95 RON and 80-83 MON) and may make up 30 vol-% or more of the refinery gasoline pool. Some typical characteristics of light FCC products from highconversion operations (VGO Feed, 1.0 wt% sulfur) are:.

(25) 157048 Introduction Page 22. . LPG: 500 - 1500 wppm total sulfur 30 - 40 vol-% C3 olefins 34 - 45 vol-% total C4 olefins. . Gasoline: C5 - 380F 90% point (193C 90% point) 92 - 94 RONC 0.1 - 0.2 wt-% sulfur 30 - 40 vol-% olefins 25 - 35 vol-% aromatics 0.5 - 1.0 vol-% benzene. The heavy liquid products from an FCC unit are normally LCO and clarified oil. The LCO product is normally used as a blending component in the diesel pool and/or in the heavy fuel oil pool. It is becoming increasingly common for LCO destined for diesel blending to be hydrotreated first for sulfur reduction. Clarified oil is usually blended off to the heavy fuel oil pool. In some cases, the FCC unit clarified oil is used in coker feed, for asphalt production or sold as feed for carbon black production. Some characteristics of heavy FCC products from high conversion operations (VGO Feed, 1.0 wt% sulfur) are: . Light cycle oil: 600F 90% point (316C 90% point) 20 - 26 cetane index 1 – 1.5 wt-% sulfur 75 - 80 vol-% aromatics 3 - 3.5 cSt @ 122F (50C). . Clarified slurry oil: 2 - 3 wt-% sulfur 9 - 13 cSt @ 210F (100C). . Source: Middle Eastern light gasoil.

(26) 157048 Introduction Page 23.

(27) 157048 Introduction Page 24. Abbreviations and Definitions ABD. average bulk density. ACFM. actual cubic feet per minute. activity. conversion of oil by test catalyst compared to standard reference feed often referred to as MAT activity. adjusted. conversion or yields reported as corrected to standard product cutpoints. afterburning. burning of CO above the dense bed in the dilute phase or flue gas, characterized by temperature increase. AGO. atmospheric gasoil. Al. aluminum. Al2O3. alumina. APS. average particle size. AR. atmospheric column resid. ash. non-combustible particles remaining after burning of a main column bottoms sample. as produced. conversion or yields reported as percent of fresh feed at the actual product rates not adjusted to standard product cut points. ASTM. American Society for Testing and Materials. ßo. Coefficient of thermal expansion at 60°F, (1/°F). behind in burning. insufficient coke combustion in regenerator, characterized by increased coke production in reactor and dark grey regenerated catalyst (high carbon on regenerated catalyst). BPD. barrels per day.

(28) 157048 Introduction Page 25. BS & W. bottoms sediment and water, normally reported in vol-%. C1, C2. methane, ethane, .... C3=. olefin (propylene). caustic. sodium hydroxide. CCR. catalyst circulation rate. CFR. combined feed ratio (volume of fresh feed plus recycle, divided by volume of fresh feed). CN-. cyanide ion. CO2/CO. mole ratio of carbon dioxide to carbon monoxide, indicates degree of partial combustion. cold regenerator. operation in conventional controlled regenerator afterburning mode of regeneration. conversion. measure of the rate of gasoil disappearance (or conversion) from feed to products defined as. COS. carbonyl sulfide. CRC. carbon on regenerated catalyst. CSO. clarified slurry oil. Cu. copper. DA, DS, DG. reactor or regenerator purges using air, steam or gas, respectively. P, DP. pressure drop or pressure difference between two points. dry gas. gas from sponge absorber (usually refers to C2-). EP. end point of distillation. F-1. research octane number (RON). F-2. motor octane number (MON).

(29) 157048 Introduction Page 26. Fe. iron. Fines. catalyst particles less than 20 microns diameter. Fm. feed metals factor. Gasoline efficiency. ratio of liquid vol-% gasoline to vol-% conversion, indicates selectivity to produce gasoline. GC, GLC. gas chromatography, gas/liquid chromatography. Gb. Fluid gravity at base temperature (60°F). Gf. fluid gravity at flowing temperature. gpm. gallons per minute. H2/C1. ratio of moles hydrogen to moles of methane. H2S. hydrogen sulfide. HC. hydrocarbon. HCN. heavy cat naphtha product drawn from the side of the main column. HCO. heavy cycle oil. HPS. high pressure separator. H. enthalpy (heat) difference. IBP. initial boiling point of distillation. K (UOP K). measure of paraffinicity or aromaticity of hydrocarbon. lb/Bbl (#/Bbl). pounds per barrel. LCO. light cycle oil. LV-%. liquid volume percent. M. prefix for thousand. MC. main column.

(30) 157048 Introduction Page 27. MCB. main column bottoms product. MON. motor octane number. MW. molecular weight. N (or N2). nitrogen. Na. sodium. NH3. ammonia. Ni. nickel. NOx. nitrogen oxides. O (or O2). oxygen. ppm. parts per million. Pf. Pressure at flowing conditions (absolute). recycle. normally refers to heavy oil from main column which has already passed through the reactor that is returned with the fresh feed to the reactor, this could also refer to light material such as LCO or gasoline; a stream which returns to its source.. RE (or Re2O3). rare earth (or rare earth oxide). Rg. regenerator. RON. research octane number. RSH. mercaptan sulfur. RVP. Reid vapor pressure. Rx. reactor. SA. surface area. SCF/Bbl (SCFB). standard cubic feet per barrel of fresh feed.

(31) 157048 Introduction Page 28. SCFD. standard cubic feet per day. selectivity. preferential towards specified goal or species. severity. combines different factors to give an overall qualitative measurement of extent or difficulty in cracking and regeneration. Si. silicon. Si2O3. silica. sintering. closure of catalyst pores. SOX. sulfur oxides. spillback. gas recycle, may also refer to liquid recycle. SS. stainless steel, also second stage. Tf. temperature at flowing conditions (absolute). V. vanadium. VGO. vacuum gasoil. vol-%. volume percent. wt-%. weight percent.

(32) 157048 Introduction Page 29. UOP P&I Diagram Abbreviations AR. Analysis Recorder. ARC. Analysis Recording Controller. DR. Specific Gravity Recorder. FA. Flow Alarm. FE. Orifice Flange Assembly. FFRC. Flow (ratio) Recording Controller. Fl. Flow Indicator. FIC. Flow Indicator Controller. FIF. Flow Indicator Flow Type. FQI. Flow Meter Displacement Type. FR. Flow Recorder. FRA. Flow Recording Alarm. FRC. Flow Recording Controller. FRCF. Flow Recording Controller Float Type. FRCQI. Flow Recording Controller Integrator. FRQI. Flow Recorder Integrator. FRQIA. Flow Recorder Integrator Alarm. HC. Hand Control. II. Current Indicator. LA. Level Alarm. LC. Level Controller. LG-B. Gage Glass Boiler Type—Visible Length Shown.

(33) 157048 Introduction Page 30. LG-R. Gage Glass Reflex Type—Visible Length Shown. LG-RLT. Gage Glass Reflex Type Visible Length Shown—Low Temperature. LG-T. Gage Glass Through View Type Visible Length Shown. LG-TK. Gage Glass Through View Type Visible Length Shown—KEL-F. LG-TLT. Gage Glass Through View Type Visible Length Shown—Low Temperature. Ll. Level Indicator. LIA. Level Indicating Alarm. LIC. Level Indicating Controller. LR. Level Recorder. LRA. Level Recording Alarm. LRC. Level Recording Controller. PA. Pressure Alarm. PC. Pressure Controller. PDC. Pressure Differential Controller. PDI. Pressure Differential Indicator. PDIC. Pressure Differential Indicating Controller. PDR. Pressure Differential Recorder. PDRA. Pressure Differential Recording Alarm. PDRC. Pressure Differential Recording Controller. PDRCA. Pressure Differential Recording Controller Alarm.

(34) 157048 Introduction Page 31. PI. Pressure Indicator. PIA. Pressure Indicating Alarm. PIC. Pressure Indicating Controller. PR. Pressure Recorder. PRA. Pressure Recording Alarm. PRC. Pressure Recording Controller. SI. Speed Indicator. SR. Speed Recorder. TA. Temperature Alarm. TC. Temperature Controller. TDR. Temperature Differential Recorder. TDRA. Temperature Differential Recording Alarm. TDRC. Temperature Differential Recording Controller. TI. Temperature Indicator. TIC. Temperature Indicating Controller. TIX. Temperature Indicator Skin. TR. Temperature Recorder. TRA. Temperature Recording Alarm. TRC. Temperature Recording Controller. TRX. Temperature Recorder Skin. TW. Thermowell. Zl. Valve Position Indicator.

(35) 157048 Introduction Page 32. When Instruments Are Designated with an Alarm H. Indicates High. HH. Indicates High-High, typically in association with an Emergency Shutdown (ESD) system trip point. L. Indicates Low. LL. Indicates Low-Low, typically in association with an Emergency Shutdown (ESD) system trip point.

(36) 157048 Process Flow Page 1. PROCESS FLOW INTRODUCTION The modern Fluid Catalytic Cracking unit is a large and complex process for cracking heavy gas oil to lighter hydrocarbons. FCC has largely replaced the old thermal crackers because it is a more efficient process, i.e. more production of valuable products at a lower overall cost by using catalyst and heat instead of simply heat. In its simplest form, the process consists of a reactor, a catalyst regenerator, and product separation. This is shown in Figure 1. Catalyst circulation is continuous, at very large mass flow rates. For this reason, the reactor and regenerator are usually discussed as one section. The product separation is usually divided into its low and high pressure components, i.e. the main column section, and the gas concentration and recovery section.. Figure 1: Fluid Catalytic Cracking Process Flue Gas. Regenerator. Air. Catalyst Transfer Lines. Products Reactor. Raw Oil. Product Separation.

(37) 157048 Process Flow Page 2. Reactor-Regenerator This is the heart of the process, where the heavy feed is cracked. The reaction products range from oil which is heavier than the charge to a light fuel gas. The catalyst is continuously regenerated by burning off the coke deposited during the cracking reaction. This provides a large measure of the heat required for the process.. Main Column The main column cools the reactor vapors and begins the separation process. A heavy naphtha fraction and light and heavy fuel oils (LCO and CLO) come off the tower as products; gasoline and lighter materials leave the top of the tower together and are cooled and separated further into product streams in the gas concentration section.. Gas Concentration and Recovery This section separates the main column overhead into gasoline, liquefied petroleum gas, and fuel gas streams. The composition of each stream is controlled for maximum product value. Figure 2 shows a slightly more detailed schematic of an FCC unit..

(38) Raw Oil. Catalyst Section. MCB HCO. Steam. Light Naphtha. Fuel Gas. Flue Gas. FCC-PF002. LPG. Gas Con Section. Flue Gas Cooler BFW. Heavy Naphtha. LCO. Main Column Section. Power Recovery Section. Figure 2 FCC Block Flow Diagram. 157048 Process Flow Page 3.

(39) 157048 Process Flow Page 4. PROCESS FLOW DESCRIPTION Reactor-Regenerator The FCC process was developed in the early 1940's. A number of companies participated in the early stages of the work, so most of the early units were virtually identical. The first design, the Model I, was installed at only three refineries and quickly replaced by a more successful Model ll. Thirty-one of these were built, thirteen designed by UOP. Figures 3 and 4 show the configurations of the Model I and the Model II FCC’s, respectively. The Model II units had double slide valves and long standpipes, which were a prime source of operating problems due to loss of catalyst fluidization in the standpipes. The raw oil charge passed through a dense bed of fluidized catalyst in the reactor vessel; however, evidence indicated that a large part of the desired cracking was occurring in the transfer line where the hydrocarbon first contacted the catalyst. The early units used low activity catalysts by today's standards, starting with natural clay and later progressing to amorphous synthetic silica/alumina catalysts. Large amounts of heavy oil were recycled back to the reactor in order to obtain the desired conversion levels of 40-60 vol-%. UOP introduced a major departure from the Model ll design in 1947. The regenerator riser was eliminated and the regeneration air was injected directly into the regenerator dense bed. Single slide valves and the more compact design cut construction costs. An important feature of the design was a long reactor riser, which was a major advantage as FCC technology advanced toward entirely riser cracking. The UOP Stacked FCC design proved to be quite popular and UOP designed about 50 Stacked FCC units. Figure 5 shows the typical arrangement of the UOP Stacked FCC unit..

(40) 157048 Process Flow Page 5. Figure 3: Model I FCC Cottrell Precipitator. Flue Gas. Catalyst Fines. Products to Main Column. Cyclones. Hoppers Air or Steam. Steam. Standpipes. Regenerator Reactor. Steam Regenerator Riser Water. Catalyst Recycle Cooler. Raw Oil Charge. Reactor Riser. Fired Heater FCC-PF003.

(41) 157048 Process Flow Page 6. Figure 4 Down-flow Model II Catalytic Cracking Unit. Flue Gas. Cottrell Precipitator. Waste Heat Boiler. Multicyclones Regenerator Products to Main Column. Reactor. Steam to Stripping Section Raw Oil Charge MCB Recycle. Air. FCC-PF004.

(42) 157048 Process Flow Page 7. Figure 5 UOP Stacked Fluid Catalytic Cracking Unit To Main Column Cyclone. Flue Gas. Reactor. Orific Chamber Spent Catalyst Stripper. Flue Gas Slide Valve. Stripping Steam. Regenerator Spent Catalyst Slide Valve. Regenerated Catalyst Slide Valve Air Slurry Recycle. Raw Oil Charge. HCO Recycle FCC-PF005.

(43) 157048 Process Flow Page 8. The next advance in reactor-regenerator design was the Side-by-Side unit, shown in Figure 6. This design was better for larger units, where stacking the reactor on top of the regenerator became more expensive. The Side-by-Side layout has also been used for many of the new small units. The straight riser showed less erosion than the curved riser of the Stacked unit. Some of the Side-by-Side units were designed with a reactor dense bed. This bed was eliminated with the advent of zeolite cracking catalysts, and the riser was extended within the reactor to minimize thermal and catalytic cracking by reducing vapor residence time in the vessel. Initially, cyclones were installed on the riser to separate the oil and catalyst, but this was not particularly successful due to poor cyclone performance. The riser cyclones were replaced by a "Tee" shaped termination at the top of the riser. The riser cyclone could then be moved over to allow room for the addition of another cyclone at the reactor outlet, providing two stages of cyclone separation. Later advances in riser termination devices concentrated on maximizing hydrocarbon containment or minimizing the post-riser residence time in the reactor shell where non-selective, thermal and secondary cracking reactions occur. Side-by-Side units have won good acceptance by the industry and over 75 UOP designed Side-by-Side FCC units have been built. Zeolite cracking catalysts were developed in 1963 and gradually accepted by the industry over the next ten years. These catalysts proved to be much more active than amorphous catalysts and were ideally suited for the short contact time riser cracker. Conversion levels rose as high as 80% without requiring excessive reactor temperature. Another significant improvement in FCC reactor technology was the use of elevated feed distributors. The older wye feed distributors injected the raw oil charge into a highly back-mixed catalyst flow that resulted in non-uniform oil/catalyst mixing and excessive light gas and coke formation. In newer systems, multiple, radially oriented feed distributors elevated in the riser inject raw oil more uniformly to maximize selectivity to desired products..

(44) 157048 Process Flow Page 9. New regenerator designs were also developed over the years. The old perforated plate air distributor was changed to a pipe grid for better air distribution. Two stage cyclones replaced single stage cyclones and reduced catalyst losses. The burning of coke in the old regenerators was not complete, i.e., not all the carbon went to CO2, and the flue gas normally contained 6-10 vol-% CO. The unit ran with no excess oxygen. This prevented afterburning in the cyclones and the resultant heat damage to the cyclones. An extra furnace to generate steam, the CO boiler, was added to utilize heat that would otherwise be lost. All of the excess CO in the flue gas could be burned in the CO boiler, but capital costs were high. The obvious solution to this problem was to burn all of the CO to CO2 in the regenerator, where the catalyst can absorb the heat. Although this could be done in a standard “bubbling bed” regenerator, a new, “high efficiency” type regenerator design proved more efficient. In the high efficiency or combustor style regenerator, shown in Figure 7, the air and catalyst is mixed in a fast fluidized environment in the lower part of the regenerator or combustor. The fluidized catalyst is then carried up the combustor riser to the upper regenerator. The fluidization in the combustor provides excellent air/catalyst mixing and heat transfer to maximize coke burning kinetics. The high efficiency regenerators on stream average less than 100 ppm CO, and less than 40 ppm NOx in the flue gas. This design enables refineries to get greater thermal efficiency from the unit while simultaneously meeting more stringent air quality standards..

(45) 157048 Process Flow Page 10. Figure 6 UOP Side by Side Fluid Catalytic Cracking Unit Rxn Products to Main Column. Reactor Down-Turned Arm. Flue Gas. Flue Gas Slide Valve. Stripping Steam. Bubbling Bed Regenerator. Spent Catalys Slide Valve. Main Distributo. Air. Regenerated Catalys Slide Valve. Wy Section Raw Oil Feed.

(46) 157048 Process Flow Page 11. Figure 7 Modern UOP Side by Side Fluid Catalytic Cracking Unit With High Efficiency Regenerator, Elevated Feed Distributors and Vortex Separation System Riser Termination.

(47) 157048 Process Flow Page 12. The process flow of the reactor and regenerator section of a typical, modern FCC unit with a high efficiency regenerator can be described as follows: Lift steam and/or light hydrocarbon is injected at the base of the riser or Wye to accelerate the catalyst from towards the elevated feed distributors, which are located about 1/3 the way up the riser. The preheated raw oil charge is pumped through the feed distributors and atomized with the addition of steam then injected into the regenerated catalyst stream. The heat from the catalyst and reduced hydrocarbon partial pressure in the riser both act to help vaporizes the oil. The catalyst, oil and steam travel up the riser to a region of lower pressure in the reactor where the cracked hydrocarbon products are separated from the catalyst in the riser termination device and cyclones before going to the main column for initial product separation. During the cracking reaction, a carbonaceous by-product called coke is deposited on the circulating catalyst. This catalyst (referred to as spent catalyst) drops from the reactor disengager and cyclones into the stripping section where a countercurrent flow of steam is used to remove both interstitial and some adsorbed hydrocarbon vapors. The stripped catalyst flows from the reactor stripper through the spent catalyst standpipe to the regenerator, where the coke is continuously burned off. The catalyst flow through the spent catalyst standpipe is controlled to balance the circulating catalyst flow by maintaining a constant catalyst level in the reactor. In the regenerator, the spent catalyst mixes with air and hot regenerated catalyst from the recirculation catalyst standpipe at the base of the combustor. Here the coke deposited during in the reactor is burned off to reactivate the catalyst and provide heat for the net endothermic cracking reactions. The heat of combustion raises the catalyst temperature in the regenerator to a range of 1200°F-1375°F (648°C-746°C). The catalyst and air flow up the combustor riser and separate at a "Tee" shaped head. The flue gas is further "cleaned" of catalyst in the cyclones in the upper regenerator. The recirculation catalyst standpipe returns some of the hot regenerated catalyst to the combustor either on temperature or density control to provide heat for initiation of the carbon burn. The remainder or the regenerated.

(48) 157048 Process Flow Page 13. catalyst flows down the regenerated catalyst standpipe on reactor temperature control to the riser Wye to complete the cycle. The flue gas exits the regenerator through the flue gas slide valves on pressure control to the regenerator. An orifice chamber located downstream of the slide valves acts to reduce the pressure drop and velocity across valves to minimize mechanical deflection of the body and erosion to the internals. Many units have a power recovery unit in place of the slide valve and orifice chamber to recover electrical energy by letting down the high volume, moderate pressure flue gas across a turbo-expander connected to a motor/generator. Finally the sensible heat energy in the flue gas is recovered through steam generation in either a CO boiler or flue gas cooler depending on the mode of operation in the regenerator. Many units also have an electrostatic precipitator or wet gas scrubber to remove catalyst fines from the flue gas before it is discharged to the atmosphere. The reasons and methods for varying the high efficiency regenerator operation will be discussed in more detail later in the PROCESS VARIABLES section. RFCC Regenerator As a result of the crude oil embargoes and oil price rises of the 1970’s, interest in processing heavier feeds in FCC units grew. However, FCC technology at that time could not handle highly contaminated heavy feeds while maintaining a reasonable degree of conversion. In the mid 1970’s, UOP and Ashland Oil Company embarked on a joint development project to develop catalytic cracking technology capable of processing very heavy, highly contaminated feeds, i.e. feeds with high metals and Conradson carbon contents. The result of this development program was the commercialization of the RCCSM (Reduced Crude Conversion) process at Ashland’s Catlettsburg refinery in 1983. The main feature of the RCC unit is a two stage regenerator equipped with a catalyst cooler to remove heat from the regenerator. The upper or first stage regenerator burns approximately 2/3 of the coke from the catalyst in partial combustion mode to limit the heat of combustion and therefore the temperature of.

(49) 157048 Process Flow Page 14. the catalyst. A portion of the partially regenerated catalyst entering the lower or second stage regenerator flows through the catalyst cooler(s) where heat is removed from the catalyst to generate steam. The cooled catalyst and the remainder of the hot catalyst from the first stage regenerator mix in the second stage regenerator where the coke burning is completed under conditions of complete CO combustion in the presence of excess O2. Carbon is burned off the catalyst to low levels in the second stage regenerator at moderate temperature to maximize catalyst activity. The combustion gases from the second stage regenerator pass into the first stage regenerator where the pre-heated excess O2 improves coke burn kinetics, and is completely consumed. The combined flue gas exits through two stages of cyclones in the first stage regenerator and out through a single common flue gas line. The overall mode of combustion for the two stage regenerator is partial burn with the additional benefit that all of the catalyst returning to the reactor is fully regenerated due to the full burn environment of the second stage regenerator. Figure 8 shows the arrangement of the regenerator of an RFCC unit. The reactor is the same as the modern Side by Side unit shown in Figure 7. Figure 9 shows the process flow for a catalyst cooler. Although catalyst coolers are not a new idea for FCC service, past attempts to employ catalyst coolers on FCC’s have been largely unsuccessful from both mechanical and process points of view. UOP’s catalyst cooler represents an improved design developed and refined to provide both mechanical reliability and a wide range of heat removal flexibility. Heat removal varies with the rate of fluidization air injected to the cooler and the catalyst slide valve opening. The operation of the catalyst cooler is as follows; catalyst enters the cooler shell where the tube bundle is immersed in hot fluidized catalyst. Fluidization air is injected at the bottom of the cooler shell to control the fluidization and heat transfer. Annular bayonet type water tubes are used in the tube bundle. Water entering the bundle flows up through the inner tube, flows out the top of the inner tube and down through the annular space between the inner and outer tubes where heat transfer occurs and water is vaporized to steam. In flow-through style coolers cooled catalyst exits the cooler shell through a standpipe and slide valve and is returned to.

(50) 157048 Process Flow Page 15. the regenerator to allow hot catalyst to enter the top of the cooler to maximize the cooler duty. Back-mix type coolers rely only on fluidization and back-mixing to transfer hot catalyst from the regenerator rather than using catalyst flow through a standpipe. Back-mix coolers have a simpler mechanical configuration but can only remove approximately 70% of the heat transfer capable through a flow-through cooler. A large excess of water is circulated through the tubes where heat transfer generates steam to ensure that the tube walls are always wet and cooled. The steam and water mixture returns from the cooler bundle to a steam drum where the steam and water are separated. Water from the drum is circulated back to the cooler and the saturated steam from the steam drum is routed to the refinery steam system..

(51) 157048 Process Flow Page 16. Figure 8 UOP RFCC Regenerator Process Flow Flue Gas. Spent Catalyst from Reactor. 1st Stage Regenerator. Vent Tubes. Catalyst Cooler. First Stage Air. 2nd Stage Regenerator. Water/ Steam Water. Recirculation Catalyst Standpipe Regenerated Catalyst to Reactor Second Stage Air.

(52) 157048 Process Flow Page 17. Figure 9 UOP FCC Catalyst Cooler Process Flow Water and Steam Saturated Steam to Superheater Fluffing Air. Makeup BFW Blowdown. Cooled Catalyst Slide Vlave. Circulating Water. FCC-PF009.

(53) 157048 Process Flow Page 18. Main Column The main column is the first step in the separation and recovery of the cracked hydrocarbon vapors from the FCC reactor. The reaction products enter the column at high temperatures, 900-1022°F (480-550°C). The main column is similar to a crude tower, with two important differences: 1) The vapors must be cooled before fractionation can begin, and 2) a large quantity of lighter gas passes overhead with the gasoline. Figure 10 shows the general process flow for an FCC main column. Large quantities of heavy oil are circulated over a series of disc and doughnut trays to cool the vapors and wash down entrained catalyst. The heat removed by the main column bottoms and the heavy cycle oil is used for feed preheat, steam generation, reboiler heat in the rest of the unit, or some combination of the three. The catalyst washed out of the reactor is concentrated in the main column bottoms stream. Most of the bottoms flow is directed through exchangers for heat removal and returned to the disc and doughnut trays. The return line must be free draining to avoid plugging problems with catalyst fines settling in low points. Some of the cooled bottoms material from the steam generators may be returned directly to the bottom of the tower as quench to reduce the temperature of the liquid and minimize coking and fouling in the bottoms system. Figure 11 shows a typical process flow for the main column bottoms pumparound and product circuit. Many older units used a slurry settler to separate and return catalyst fines to the reactor with a slurry stream off the bottom of the settler. The main column bottoms product comes off the top of the settler and is normally called clarified slurry oil. In reactors with two stages of cyclones and in units with modern riser termination devices, the use of slurry settlers has normally been discontinued. Heavy bottoms product comes directly from the main column bottoms circulating stream, as does any slurry recycle to the reactor..

(54) 157048 Process Flow Page 19. Figure 10 UOP FCC Main Column To Wet Gas Compressor CW. To Sour Water. To Primary Absorber. 1 5 6. Gas Concentration Unit. FI 7. 19 21. FI 22. Equalizing Line to/from Feed Drum. Steam. 26 27 29. 30. Heavy Naphtha Product Gas Concentration Unit. Steam. 32. Light Cycle Oil Product. 33. Flushing Oil. 34 35. Gas Concentration Unit. 36. Flushing Oil 37. Torch Oil 38. Reactor Vapors. Steam. BFW. Main Column Bottoms Product CW. Raw Oil from Surge Drum. Raw Oil to Reactor.

(55) 157048 Process Flow Page 20. Figure 11 UOP FCC Main Column Bottoms Process Flow. 6 Minimum Spillback. MCB Product Circuit Minimum Flow Valve. 3. 1. E FRC. Main Column. Rx Overhead. E. MCB Product Pumps. E. E. Tempered Water. Quench. Steam. Steam Main Column Bottoms Circulation Pumps. MCB Product. MCB Steam Generators Water. Raw Oil Water. Circulating Bottoms/ Raw Oil Exchanger. Raw Oil. Net Bottoms/ Raw Oil Exchanger.

(56) 157048 Process Flow Page 21. As previously mentioned, most FCC units with modern riser terminations and reactor cyclones do not require the use of a slurry settler and new units currently being designed do not include settlers. If a refiner has strict specifications on the ash content of the main column bottoms product, then more advanced alternate fines removal equipment is usually employed to reduce the catalyst fines to very low levels. The two most common types of catalyst removal equipment used today are the micromesh filter and the electrostatic separator. Cyclonic separation devices have also been used, but are typically limited to smaller capacity installations. A typical micromesh filter system will have 2 or 3 vessels with up to 100 filter elements in each. When multiple filtration vessels are used, each filtration vessel is sized for 100% of the design flow rate. One vessel is typically in filtration mode while another is in backflush mode to remove the filter cake from the elements. When enough catalyst fines have deposited on the filter elements to increase the pressure drop across the filter to a pre set limit, the vessel is taken off line for back flushing. Once the filter vessel is off line and drained the vessel is filled with backflush liquid, either HCO or LCO, and allowed to soak to help dissolve any heavy aromatic compounds on the elements. The top of the vessel is then pressured up with either fuel gas or nitrogen to provide the driving force for a high velocity back flush. The back flush material is collected in a receiver vessel and pumped back to the reactor riser. A typical process flow for the micromesh filtration system is shown in Figure 12. A typical electrostatic slurry oil filtration unit consists of 4-16 skid mounted cylindrical shells (modules) depending on the volume of filtrate to be process. Each module contains a high voltage cylindrical electrode surrounded by conductive glass beads, with a ground rod located in the center of the module assembly. During the separation cycle, the glass beads are ionized in an electrostatic field. As catalyst particles flow between the beads, they are electrostatically collected on the surface of the beads. Each module is sequentially back-flushed while the remaining modules in the system continue the separation. In the backflush cycle, the electrode is de-energized and the beads are fluidized, resulting in a circulating motion up through the center of a 9-inch annular electrode and down the outside. The circulation up the center annulus and down the walls of the module creates a scrubbing action, to mechanically scrub the beads clean. Mechanically scrubbing.

(57) 157048 Process Flow Page 22. the beads as opposed to solvent soaking as with the micro-mesh filters, raw oil feed, or any compatible oil can be used as the backflush medium to an electrostatic filter. The back flush material is directed back to the reactor riser.. Figure 12 Main Column Bottoms Product Filtration System Backwash Gas (N2 or Fuel Gas). Clean MCB Product to Storage. Filter #1. Filter #2. Filter #3. N2 or Fuel Gas Vent. Back Flush Liquid (LCO/HCO) MCB Product. Receiver Vessel. Catalyst Backwash to Reactor.

(58) 157048 Process Flow Page 23. There are typically three side-cuts withdrawn from the main column, heavy cycle oil (HCO), light cycle oil (LCO), and heavy naphtha (HCN). The refiner may withdraw all three, only two or one, depending on product needs and tower design. On relatively rare occasions, the main column is designed with a fourth side-cut to discretely fractionate a heavy LCO cut and a light LCO cut. The side-cut streams that go out as product are usually stripped to meet flash-point specifications. Pumparound loops from these side-draws are used to heat balance the main column by exchanging heat with the gas concentration unit reboilers, the raw oil charge or boiler feed water. The heat removed in the bottom and side pumparounds determines the amount of reflux in each section of the tower and must be properly balanced for proper column operation. Gasoline and light gases pass up through the main column and leave as vapors. After being cooled and condensed, unstabilized gasoline is pumped back to the top of the column as reflux to control the top temperature in the column. Figures 13, 14, 15 and 16 show typical process flows for the HCO pumparound, the LCO pumparound, the Heavy Naphtha pumparound and the Main Column Overhead system, respectively..

(59) 157048 Process Flow Page 24. Figure 13 Main Column HCO Pumparound. E. Main Column. LIC. E. Gas Con Unit Debutanizer Reboiler. HCO Internal Reflux (Pumped). To MCB/Feed Exchanger Outlet (for startup) Filling Line (from feed pump). E. Heavy Cycle Oil Circulation Pumps. To Feed Surge Drum (normally no flow) To Pump Flushing Oil Supply Header.

(60) 157048 Process Flow Page 25. Figure 14 Main Column LCO Pumparound and Product. FI FIC LIC Steam. FIC LCO Product. BFW CW Preheater. FIC. LCO to Flushing Oil. Debutanizer Feed Exchanger. FIC Stripper Reboiler Rich Oil from Sponge Absorber Lean Oil to Sponge Absorber FCC-PC403.

(61) 157048 Process Flow Page 26. Figure 15 Main Column Heavy Naphtha Pumparound and Product. Main Column C3/C4 Splitter Reboiler. E. E. Circulating Naphtha/ Debutanizer Feed Exchanger. Steam E FRC. Heavy Naphtha Stripper. LCO Stripper. Reflux (Gravity Flow). LIC. Heavy Naphtha Circulation Pumps Heavy Naphtha Product Pumps Heavy Naphtha Product Cooler HeavyNaphtha to and from NHT Unit Signal from HCN Hydrotreater. CW FRC E. Hydrotreated Heavy Naphtha Product.

(62) 157048 Process Flow Page 27. Figure 16. Main Column Overhead System. FCC/DS-R00-37.

(63) 157048 Process Flow Page 28. The raw oil feed system is included in the main column section for better process efficiency, i.e. to take advantage of the heat from the main column. Feed enters the unit from storage or directly from upstream processes, such as a vacuum tower or a hydrotreater. The latter scheme is more efficient because the feed will not have to be cooled before storage and then reheated flowing into the FCC. The number and type of exchangers used will depend on cost and process factors that will vary with each refinery. Most newer units do not use fired charge heaters. Fired charge heaters have become unpopular due to the increases in fuel costs, operational safety and impact on overall refinery stack emissions. The feed goes directly to the riser after the raw oil/main column bottoms exchanger. Figures 17 and 18 show typical process flow schemes for the FCC feed preheat system without a fired charge heater and with a fired charge heater, respectively.. Figure 17 Feed Preheat Equalizing Line To/From Main Column. Raw Oil Surge Drum. Raw Oil from Crude Unit/ Hydrotreating. To Reactor LCO Product. MCB Product. Circ. MCB. MCB Recycle HCO Recycle FCC-PF401.

(64) 157048 Process Flow Page 29. Figure 18 Feed Preheat with Fired Heater. Equalizing Line To/From Main Column. Raw Oil Surge Drum. Fired Heater Raw Oil from Storage/ Upstream Unit. MCB Product. To Reactor. Circ. MCB. Fuel Gas. FCC-PF401.

(65) 157048 Process Flow Page 30. Gas Concentration and Recovery This section further separates the main column overhead products into stabilized gasoline, LPG and fuel gas. The normal configuration is shown in Figure 18. Unstabilized gasoline from the main column overhead receiver is pumped to the primary absorber, where it is used to adsorb C3’s and C4’s in the gas stream at much higher pressure than the main column. From here the liquid stream goes to the high pressure receiver (separator), then the stripper column, where H2S and C2- are removed. The gasoline off the bottom of the stripper is pressured to the debutanizer for separation of LPG and gasoline and vapor pressure adjustment of the gasoline. The overhead of the debutanizer is olefins rich LPG which is often further processed, for C3 and C4 separation and propylene recovery. The gas from the main column overhead receiver goes first to the wet gas compressor. From here it is pressured to the HPS, the primary absorber, and finally the sponge absorber. Valuable light products such as LPG are removed in the first of two vessels by absorption into the gasoline. The second vessel is the sponge absorber which uses a LCO pumparound from the main column as a final absorption stage before the gas goes out as fuel. Wash water, typically clean condensate, is injected into the inlet to the wet gas compressor interstage condenser. From the interstage receiver it is pumped to the high pressure receiver then to the main column overhead condensers. This water washes out salt forming and corrosive and species such as H2S, NH3, cyanides and phenols. The wash water flow is shown in Figure 19..

(66) D HPR IR PA SA S WGC. HPR. Wash Water to MC OVHD Receiver. IR. Debutanizer High Pressure Receiver Interstage Receiver Primary Absorber Sponge Absorber Stripper Wet Gas Compressor. Legend:. Wash Water. WGC. Gas from MC Overhead Receiver. Gasoline from MC Overhead Receiver. 40. P A. 9. 1. Rich Lean Oil Oil. S A 36. S. 1. Typical Gas Concentration Unit Process Flow. Figure 19:. 40. D. 1. Stabilized FCC Gasoline. HCO. LPG. Fuel Gas. 157048 Process Flow Page 31.

(67) Main Column. Hydrocarbon Water. Condensate. To Sour Water Stripper WGC 1st Stage. Main Column Receiver. Interstage Drum. Wash Water Flow. Figure 20:. WGC 2nd Stage. High Pressure Receiver. 157048 Process Flow Page 32.

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